EX-99.1 3 h36099exv99w1.htm MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS exv99w1
 

EXHIBIT 99.1
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis should be read in conjunction with our consolidated financial statements included in Exhibit 99.2 of this Current Report on Form 8-K. The following information contains forward-looking statements, which are subject to risks and uncertainties. Should one or more of these risks or uncertainties materialize, our actual results may differ from those expressed or implied by the forward-looking statements. See “Forward-Looking Statements” at the beginning of our Annual Report on Form 10-K for the year ended December 31, 2005.
Executive Summary
We are a leading provider of specialized oilfield services and equipment focused on serving the drilling-related needs of oil and gas companies primarily through our rental tools segment, and the production-related needs of oil and gas companies through our well intervention, rental tools and marine segments. In recent years, we have expanded geographically so that we now have a growing presence in select domestic land and international markets. We also own and operate, through our subsidiary SPN Resources, LLC, mature oil and gas properties in the Gulf of Mexico.
The oil and gas industry remains highly cyclical and seasonal. Activity levels in our service and rental tools segments are driven primarily by traditional energy industry activity indicators, which include current and expected future commodity prices, drilling rig count, oil and gas production levels, and customers’ capital spending allocated for drilling and production.
The primary factors driving our performance in 2005 were (1) increased customer spending levels on finding and replacing oil and gas reserves due to high commodity prices; (2) increased customer focus on replacing reserves through production-enhancement projects in existing wells; and (3) the active hurricane season, which disrupted a strong Gulf of Mexico market, but created incremental long-term demand for our products and services.
In 2005, activity across all segments increased throughout the year, particularly in the Gulf of Mexico. However, the extraordinarily active hurricane season — highlighted by damage caused by Hurricanes Katrina and Rita — disrupted most Gulf of Mexico-based well intervention service and rental tool activity for almost three months following the storms.
By mid-November, pre-storm Gulf activity levels resumed for well intervention services and rental tools and by year-end demand for most services and tools were exceeding those levels. The marine segment participated in post-storm damage assessment and construction support projects throughout the fourth quarter. By the end of the year, liftboat demand continued to grow due to the post-hurricane construction and repair work, coupled with well intervention work that was deferred prior to the storms. This led to unprecedented dayrates for liftboats as year-end dayrates were 50% higher than rates in August 2005, and 30% higher than dayrates we were generating during the second and third quarters of 2001 when prior peak dayrates were established. Also, for the first time in several years, we were able to achieve meaningful price increases for some of our well intervention services. Financial performance for services has traditionally been driven by volume, or utilization, while pricing improvement has been difficult to achieve. However, pent-up demand and incremental work created by hurricane damage have allowed us to raise prices on some services by as much as 20%.
The active hurricane season also caused significant damage to the industry’s Gulf of Mexico infrastructure. Our participation in the Gulf of Mexico repair efforts include project management; marine and well control engineering; relief well planning, supervision and execution; well intervention planning; offshore supervision and offshore site and activity management; well abandonment; and specialty equipment and tools. In addition, we will provide our liftboats, well intervention services and rental tools to many more projects that we are not managing.
Our oil and gas production remained largely shut-in following the hurricanes due to hurricane damage. During the fourth quarter, we were repairing our properties and awaiting repairs to pipelines owned by third parties. Average

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production during the second quarter of 2005, prior to the active hurricane season, was approximately 7,200 barrels of oil equivalent (“boe”) per day. However, in the third and fourth quarters, production averaged approximately 4,600 boe per day and 1,100 boe per day, respectively. All of our production is expected to be restored by the end of the first quarter of 2006.
In our other geographic market areas, we benefited from increased levels of customer spending driven by high commodity prices. International revenue was a record $99.3 million, primarily due to continued expansion of our rental tools business in markets such as the North Sea, Venezuela, the Middle East and West Africa and well intervention activity in Australia, Egypt and Venezuela. Approximately 55% of our international revenue is derived from the rental tools segment. The remainder is derived from well intervention services such as hydraulic workover, sidetrack drilling and well control services.
Domestically, we aggressively expanded our rentals of drill pipe, ancillary tubulars, handling tools, stabilizers, and drill collars to market areas in Arkansas, Louisiana, Texas, Oklahoma and Wyoming. Toward the end of the year we expanded our well intervention services in these market areas. Drilling rig counts and production-related spending are expected to grow domestically on land, and we believe we can successfully expand our presence in these market areas. As a result, demand should continue at high levels in the markets in which we compete due to the current high level of commodity prices and our customers’ focus on rapidly replacing oil and gas reserves from reservoirs that deliver the highest returns for the least amount of risk.
In the Gulf of Mexico, activity is expected to remain robust. In the deepwater Gulf, large energy producers continue to fund exploration and drilling programs in an effort to locate and produce large reservoirs of oil and gas. The shallow water Gulf is more mature, providing production-enhancement opportunities for smaller operators.
The mature nature of the shallow water Gulf market should benefit our newly constructed derrick barge — which is expected to be available during the third quarter of 2006 — and increase our ability to acquire additional mature properties. We expect decommissioning activity to accelerate as shallow water wells become uneconomical and platforms must be removed. Mature wells often require significant intervention to enhance, extend and maintain production. The costs of this intervention, coupled with the additional risks associated with hurricanes, may lead many energy producers to re-assess the costs and benefits of owning these mature properties.
Well Intervention Segment
The well intervention segment consists of specialized down-hole services, which are both labor and equipment intensive. While our gross margin percentage tends to be fairly consistent, special projects such as well control can directly increase the gross margin percentage.
Revenue and operating income were 15% and 8% higher, respectively, as compared to 2004 despite significant hurricane-related downtime in the Gulf of Mexico and non-recurring, non-cash charges of approximately $4.9 million related to the sale of our oil spill response assets and the reduction in value of our non-hazardous oilfield waste treatment business as a result of our intent to sell the business. The hurricane-related downtime was more than offset by strong Gulf of Mexico activity levels during the first half of the year, especially for services such as coiled tubing, mechanical wireline and electric line services, and improved pricing for many services toward the end of the year. In addition, year-over-year performance improved significantly for well control and hydraulic workover services in non-Gulf of Mexico markets.
Rental Tools Segment
The rental tools segment is capital intensive with high operating margins as a result of relatively low operating costs. The largest fixed cost is typically depreciation as there is little labor associated with our rental tools business. Pricing generally does not fluctuate and financial performance is a function of changes in volume rather than pricing.
Revenue increased 43% and operating income increased 68% over 2004. The biggest increases in revenue and operating income were from the rentals of drill pipe, particularly rentals in international markets, as well as rentals of on-site accommodations and handling tools. Rentals outside the Gulf of Mexico represented more than 60% of this segment’s total revenue in 2005.

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Marine Segment
The operating costs of our liftboats are relatively fixed and, therefore, gross margin percentages vary significantly from quarter-to-quarter and year-to-year based on changes in dayrates and utilization levels. As an indication of this segment’s performance, our gross margin percentages were 40% in the first quarter, 32% in the second quarter, 36% in the third quarter and 62% in the fourth quarter.
Revenue increased 25% and operating income increased more than 320% over 2004. Liftboat dayrates and utilization steadily increased during the first and second quarters of the year. Activity levels were improving in August prior to Hurricanes Katrina and Rita. Following the storms, dayrates increased to record levels and liftboat utilization averaged approximately 90% during the fourth quarter as our liftboats were used to support our customers’ damage assessment and construction projects.
We sold 17 of our smaller liftboats during the second quarter. These liftboats had lower gross profit percentages than our fleet of larger liftboats.
Oil and Gas Segment
Through our subsidiary SPN Resources, LLC, we acquire, manage and decommission mature properties in the shallow waters of the Gulf of Mexico. As of December 31, 2005, we had interests in 32 offshore blocks containing 58 structures and approximately 140 producing wells.
The main objective of this business segment is to provide additional opportunities for our products and services, especially during cyclical and seasonal slower periods. Because of the fixed cost nature of our well intervention services, the incremental cost to work on mature properties is far less than it would be for traditional energy producers. This segment provides work for our services, thereby increasing utilization of our own assets by deploying services on our own properties during periods of downtime.
The lease operating expenses for these types of properties are typically relatively high because of the amount of well intervention service work required to enhance, maintain and extend production for mature properties. The gross operating margin is also a function of oil and gas prices.
Revenues were 113% higher and operating income was 76% higher than 2004. Although we benefited from higher commodity prices and more production as a result of properties we acquired in 2004, approximately 744,000 boe of production was deferred as a result of extensive damage caused by the active hurricane season. We did not suffer any permanent damage to wells, and we expect our production to be fully-restored by the end of the first quarter of 2006.
Critical Accounting Policies and Estimates
Our discussion and analysis of our financial condition and results of operations are based on our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires us to make estimates and assumptions that affect the amounts reported in our consolidated financial statements and accompanying notes. Note 1 to our consolidated financial statements contains a description of the accounting policies used in the preparation of our financial statements. We evaluate our estimates on an ongoing basis, including those related to long-lived assets and goodwill, income taxes, allowance for doubtful accounts, self-insurance and oil and gas properties. We base our estimates on historical experience and on various other assumptions that we believe are reasonable under the circumstances. Actual amounts could differ significantly from these estimates under different assumptions and conditions.
We define a critical accounting policy or estimate as one that is both important to the portrayal of our financial condition and results of operations and requires us to make difficult, subjective or complex judgments or estimates

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about matters that are uncertain. We believe that the following are the critical accounting policies and estimates used in the preparation of our consolidated financial statements. In addition, there are other items within our consolidated financial statements that require estimates but are not deemed critical as defined in this paragraph.
Long-Lived Assets. We review long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of any such asset may not be recoverable. We record impairment losses on long-lived assets, including oil and gas properties, used in operations when the estimated cash flows to be generated by those assets are less than the carrying amount of those items. Our cash flow estimates are based upon, among other things, historical results adjusted to reflect our best estimate of future market rates, utilization levels, operating performance, and with respect to our oil and gas properties, future oil and natural gas sales prices, an estimate of the ultimate amount of recoverable oil and natural gas reserves that will be produced from a field, the timing of this future production, future costs to produce the oil and natural gas and other factors. Our estimates of cash flows may differ from actual cash flows due to, among other things, changes in economic conditions or changes in an asset’s operating performance. If the sum of the cash flows is less than the carrying value, we recognize an impairment loss, measured as the amount by which the carrying value exceeds the fair value of the asset. The net carrying value of assets not fully recoverable is reduced to fair value. Our estimate of fair value represents our best estimate based on industry trends and reference to market transactions and is subject to variability. The oil and gas industry is cyclical and our estimates of the period over which future cash flows will be generated, as well as the predictability of these cash flows, can have significant impact on the carrying value of these assets and, in periods of prolonged down cycles, may result in impairment charges.
Goodwill. In assessing the recoverability of goodwill, we must make assumptions regarding estimated future cash flows and other factors to determine the fair value of the respective assets. If these estimates or their related assumptions adversely change in the future, we may be required to record material impairment charges for these assets not previously recorded. We test goodwill for impairment in accordance with Statement of Financial Accounting Standards No. 142 (FAS No. 142), “Goodwill and Other Intangible Assets.” FAS No. 142 requires that goodwill as well as other intangible assets with indefinite lives no longer be amortized, but instead tested annually for impairment. Our annual testing of goodwill is based on our fair value and carrying value at December 31. We estimate the fair value of each of our reporting units (which are consistent with our reportable segments) using various cash flow and earnings projections. We then compare these fair value estimates to the carrying value of our reporting units. If the fair value of the reporting units exceeds the carrying amount, no impairment loss is recognized. Our estimates of the fair value of these reporting units represent our best estimates based on industry trends and reference to market transactions. A significant amount of judgment is involved in performing these evaluations since the results are based on estimated future events.
Income Taxes. We provide for income taxes in accordance with Statement of Financial Accounting Standards No. 109 (FAS No. 109), “Accounting for Income Taxes.” This standard takes into account the differences between financial statement treatment and tax treatment of certain transactions. 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. 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. Our deferred tax calculation requires us to make certain estimates about our future operations. Changes in state, federal and foreign tax laws, as well as changes in our financial condition or the carrying value of existing assets and liabilities, could affect these estimates. The effect of a change in tax rates is recognized as income or expense in the period that includes the enactment date.
Allowance for Doubtful Accounts. We maintain an allowance for doubtful accounts for estimated losses resulting from the inability of some of our customers to make required payments. These estimated allowances are periodically reviewed, on a case by case basis, analyzing the customer’s payment history and information regarding customer’s creditworthiness known to us. In addition, we record a reserve based on the size and age of all receivable balances against which we do not have specific reserves. If the financial condition of our customers was to deteriorate, resulting in their inability to make payments, additional allowances may be required.
Revenue Recognition. We recognize revenue when services or equipment are provided and collectibility is reasonably assured. Services and rentals are generally provided based on fixed or determinable priced purchase orders or contracts with customers. We contract for marine, well intervention and environmental projects either on a

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day rate or turnkey basis, with a majority of our projects conducted on a day rate basis. Our rental tools are rented on a day rate basis, and revenue from the sale of equipment is recognized when the equipment is shipped. We recognize oil and gas revenue from our interests in producing wells as the commodities are delivered, and the revenue is recorded net of royalties and hedge payments due or inclusive of hedge payments receivable.
Self-Insurance. We self-insure up to certain levels for losses related to workers’ compensation, protection and indemnity, general liability, property damage, and group medical. With the recent tightening in the insurance markets, we have elected to retain more risk by increasing our self-insurance. We accrue for these liabilities based on estimates of the ultimate cost of claims incurred as of the balance sheet date. We regularly review our estimates of reported and unreported claims and provide for losses through reserves. We also have an actuary review our estimates for losses related to workers’ compensation and group medical on an annual basis. While we believe these estimates are reasonable based on the information available, our financial results could be impacted if litigation trends, claims settlement patterns, health care costs and future inflation rates are different from our estimates. Although we believe adequate reserves have been provided for expected liabilities arising from our self-insured obligations, and we believe that we maintain adequate reinsurance coverage, we cannot assure that such coverage will adequately protect us against liability from all potential consequences.
Oil and Gas Properties. Our subsidiary, SPN Resources, LLC, acquires mature oil and gas properties and assumes the related well abandonment and decommissioning liabilities. We follow the successful efforts method of accounting for our investment in oil and natural gas properties. Under the successful efforts method, the costs of successful exploratory wells and leases containing productive reserves are capitalized. Costs incurred to drill and equip developmental wells, including unsuccessful development wells, are capitalized. Other costs such as geological and geophysical costs and the drilling costs of unsuccessful exploratory wells are expensed. SPN Resources’ property purchases are recorded at the value exchanged at closing, combined with an estimate of its proportionate share of the decommissioning liability assumed in the purchase. All capitalized costs are accumulated and recorded separately for each field and allocated to leasehold costs and well costs. Leasehold costs are depleted on a units-of-production basis based on the estimated remaining equivalent proved oil and gas reserves of each field. Well costs are depleted on a units-of-production basis based on the estimated remaining equivalent proved developed oil and gas reserves of each field.
We estimate the third party market value (including an estimated profit) to plug and abandon wells, abandon the pipelines, decommission and remove the platforms and clear the sites, and use that estimate to record our proportionate share of the decommissioning liability. In estimating the decommissioning liabilities, we perform detailed estimating procedures, analysis and engineering studies. Whenever practical, we will utilize the services of our subsidiaries to perform well abandonment and decommissioning work. When these services are performed by our subsidiaries, all recorded intercompany revenues and expenses are eliminated in the consolidated financial statements. The recorded decommissioning liability associated with a specific property is fully extinguished when the property is completely abandoned. The liability is first reduced by all cash expenses incurred to abandon and decommission the property. If the liability exceeds (or is less than) our out-of-pocket costs, the difference is reported as income (or loss) in the period in which the work is performed. We review the adequacy of our decommissioning liability whenever indicators suggest that the estimated cash flows underlying the liability have changed materially. The timing and amounts of these cash flows are subject to changes in the energy industry environment and may result in additional liabilities recorded, which in turn would increase the carrying values of the related properties.
Oil and gas properties are assessed for impairment in value on a field-by-field basis whenever indicators become evident. We use our current estimate of future revenues and operating expenses to test the capitalized costs for impairment. In the event net undiscounted cash flows are less than the carrying value, an impairment loss is recorded based on the present value of expected future net cash flows over the economic lives of the reserves.
Proved Reserve Estimates. Our reserve information is prepared by independent reserve engineers in accordance with guidelines established by the Securities and Exchange Commission and generally accepted accounting principles. There are a number of uncertainties inherent in estimating quantities of proved reserves, including many factors beyond our control such as commodity pricing. Reserve engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that can not be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation

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and judgment. In accordance with the Securities and Exchange Commission’s guidelines, we use prices and costs determined on the date of the actual estimate and a 10% discount rate to determine the present value of future net cash flow. Actual prices and costs may vary significantly, and the discount rate may or may not be appropriate based on outside economic conditions.
Derivative Instruments and Hedging Activities. We enter into hedging transactions for our oil production to reduce exposure to the fluctuations in oil prices. Our hedging transactions to date have consisted of financially-settled crude oil swaps and zero-cost collars with a major financial institution. We may in the future enter into these and other types of hedging arrangements to reduce our exposure to fluctuations in the market prices of oil and natural gas. Under the provisions of Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities,” we are required to record our derivative instruments at fair market value as either assets or liabilities in our consolidated balance sheet. The fair market value is an estimate based on future commodity prices available at the time of the calculation. The fair market value could differ from actual settlements if the other party to the contract defaults on its obligations or there is a change in the expected differential between the underlying price in the hedging agreement and actual prices received.
Comparison of the Results of Operations for the Years Ended December 31, 2005 and 2004
For the year ended December 31, 2005, our revenues were $735.3 million resulting in net income of $67.9 million or $0.85 diluted earnings per share. For the year ended December 31, 2004, revenues were $564.3 million and net income was $35.9 million or $0.47 diluted earnings per share. We experienced higher revenue and gross margin in all our segments, especially our rental tools, oil and gas and well intervention segments as activity levels increased. However, the extraordinarily active hurricane season disrupted most of our activity for several months following Hurricanes Katrina and Rita.
The following table compares our operating results for the years ended December 31, 2005 and 2004. Gross margin is calculated by subtracting cost of services from revenue for each of our four business segments. Oil and gas eliminations represent products and services provided to the oil and gas segment by the Company’s three other segments.
                                                                 
    Revenue   Gross Margin
    2005   2004   Change   2005   %   2004   %   Change
         
Well Intervention
   $ 339,609     $ 295,690     $ 43,919     $ 125,971       37 %   $ 105,832       36 %   $ 20,139  
Rental Tools
     243,536       170,064       73,472       160,974       66 %     112,711       66 %     48,263  
Marine
     87,267       69,808       17,459       39,278       45 %     20,227       29 %     19,051  
Oil and Gas
     78,911       37,008       41,903       33,107       42 %     15,461       42 %     17,646  
Less: Oil and Gas Elim.
     (13,989 )     (8,231 )     (5,758 )     —       —       —       —       —  
                                 
Total
   $ 735,334     $ 564,339     $ 170,995     $ 359,330       49 %   $ 254,231       45 %   $ 105,099  
                                 
The following discussion analyzes our operating results on a segment basis.
Well Intervention Segment
Revenue for our well intervention segment was $339.6 million for the year ended December 31, 2005, as compared to $295.7 million for 2004. This segment’s gross margin percentage increased slightly to 37% in 2005 from 36% in 2004. We experienced higher revenue for almost all of our services as production-related activity improved in the Gulf of Mexico, particularly for the well control, hydraulic workover, coiled tubing, wireline and field management services. Activity levels declined in the months following Hurricanes Katrina and Rita, but pre-storm demand levels returned near the end of the year.
Rental Tools Segment
Revenue for our rental tools segment for the year ended December 31, 2005 was $243.5 million, a 43% increase over 2004. The gross margin percentage remained unchanged at 66% for the years ended December 31, 2005 and

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2004. We experienced significant increases in revenue from our on-site accommodations, drill pipe and accessories and stabilizers. The increases are primarily the result of significant increases in activity in the Gulf of Mexico, as well as our international and domestic expansion efforts. Although our rental tools segment was negatively impacted from Hurricanes Katrina and Rita in August and September of 2005, activity levels surpassed pre-storm levels for most of our rental tools by the end of the year. Our international revenue for the rental tools segment has increased 108% to approximately $53.6 million for the year ended December 31, 2005 from 2004. Our biggest improvements were in the North Sea, Trinidad, Venezuela and Mexico.
Marine Segment
Our marine segment revenue for the year ended December 31, 2005 increased 25% over 2004 to $87.3 million. The gross margin percentage for the year ended December 31, 2005 increased to 45% from 29% for 2004. The year ended December 31, 2005 includes only five months of rental activity from the 105-foot and the 120 to 135-foot class liftboats. These 17 rental liftboats were sold effective June 1, 2005. The increase in revenue is caused by increased utilization of our fleet’s remaining larger liftboats at higher dayrates partially offset by fewer liftboats generating revenue for seven months of 2005. The increase in the gross margin percentage is also caused by increased demand and the sale of our lower margin rental liftboats. The fleet’s average dayrate increased 47% to approximately $9,223 in the year ended December 31, 2005 from $6,295 in 2004. Increased demand as well as the sale of the smaller liftboats also contributed to the increase in average dayrates. The fleet’s average utilization increased to approximately 78% for the year ended December 31, 2005 from 72% in 2004. Our liftboat fleet experienced strong increases in demand and pricing in the fourth quarter as liftboats were needed for the large amount of construction and repair work in the Gulf of Mexico as a result of hurricane damage.
Oil and Gas Segment
Oil and gas revenues were $78.9 million in the year ended December 31, 2005 as compared to $37.0 million in 2004. The increase in revenue is primarily the result of production from South Pass 60, which was acquired in July 2004, and production from West Delta 79/86, which was acquired in December 2004. We also acquired Galveston 241/255 and High Island A-309 in late-July 2005. In the year ended December 31, 2005, production was approximately 1,794,000 boe as compared to approximately 918,000 boe in 2004. The gross margin percentage remained unchanged at 42% for the years ended December 31, 2005 and 2004. The oil and gas segment was affected by significant amounts of curtailed production resulting from the active hurricane seasons the past two years resulting in deferred production as a result of Hurricanes Katrina and Rita in 2005 of approximately 744,000 boe and as a result of Hurricane Ivan in 2004 of approximately 347,000 boe.
Depreciation, Depletion, Amortization and Accretion
Depreciation, depletion, amortization and accretion increased to $89.3 million in the year ended December 31, 2005 from $67.3 million in 2004. The increase is primarily a result of depletion and accretion related to our oil and gas properties from both increased production and acquisitions of oil and gas properties. The increase also results from the depreciation associated with our 2005 and 2004 capital expenditures primarily in the rental tools segment.
General and Administrative
General and administrative expenses increased to $141.0 million for the year ended December 31, 2005 from $110.6 million in 2004. Of this increase, $5.5 million is the result of storm-related costs from Hurricanes Katrina and Rita in the third and fourth quarters of 2005 including $2.1 million in equipment and facility losses and repairs, $2.0 million in relief aid to more than 560 employees affected by the hurricanes and $1.4 million in storm-related payroll expenses, temporary lodging and miscellaneous expenses. The remaining increase was primarily related to increased payroll and bonus expenses, increased insurance costs and expenses as a result of our growth, oil and gas acquisitions and geographic expansion.
Reduction in Value of Assets
During the year ended December 31, 2005, we reduced the value of two of our mature oil and gas properties by approximately $2.1 million, thereby removing the reserve balance associated with these wells. The wells were deemed to be uneconomical to further produce as a result of the estimated costs associated with maintaining production.

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Our oil spill containment boom manufacturing facility suffered damage from Hurricane Katrina and experienced difficulty in resuming normal business operations. As a result, we elected not to reopen this manufacturing facility and sell the remaining oil spill containment boom inventory. We reduced the value of the assets of this business (which consist primarily of inventory and property and equipment) by approximately $1.1 million to the estimated net realizable value.
In the first quarter of 2006, we sold our non-hazardous oilfield waste subsidiary, Environmental Treatment Team, L.L.C. (ETT) for approximately $18.7 million in cash. We reduced the net asset value of ETT by $3.8 million in 2005 to its approximate sales price.
Gain on Sale of Liftboats
Effective June 1, 2005, we sold all of our rental liftboats with leg-lengths from 105 feet to 135 feet for $19.8 million in cash (exclusive of costs to sell), which resulted in a gain of $3.5 million.
Comparison of the Results of Operations for the Years Ended December 31, 2004 and 2003
For the year ended December 31, 2004, our revenues were $564.3 million resulting in net income of $35.9 million or $0.47 diluted earnings per share. For the year ended December 31, 2003, revenues were $500.6 million and net income was $30.5 million which includes $2.8 million of pre-tax other income due to the gain from insurance proceeds; diluted earnings per share was $0.41 for the same period. We experienced higher revenues from our rental tools and well intervention segments. We also benefited from oil and gas production following our initial acquisition of properties in the Gulf of Mexico in December 2003.
The following table compares our operating results for the years ended December 31, 2004 and 2003. Gross margin is calculated by subtracting cost of services from revenue for each of our four business segments. Oil and gas eliminations represent products and services provided to the oil and gas segment by the Company’s three other segments.
                                                                 
    Revenue   Gross Margin
    2004   2003   Change   2004   %   2003   %   Change
         
Well Intervention
   $ 295,690     $ 288,152     $ 7,538     $ 105,832       36 %   $ 95,309       33 %   $ 10,523  
Rental Tools
     170,064       141,362       28,702       112,711       66 %     95,243       67 %     17,468  
Marine
     69,808       70,370       (562 )     20,227       29 %     20,056       29 %     171  
Oil and Gas
     37,008       741       36,267       15,461       42 %     410       55 %     15,051  
Less: Oil and Gas Elim.
     (8,231 )     —       (8,231 )     —       —       —       —       —  
                                 
Total
   $ 564,339     $ 500,625     $ 63,714     $ 254,231       45 %   $ 211,018       42 %   $ 43,213  
                                 
The following discussion analyzes our operating results on a segment basis.
Well Intervention Segment
Revenue for our well intervention segment was $295.7 million for the year ended December 31, 2004, as compared to $288.2 million for the same period in 2003. This segment’s gross margin percentage increased to 36% in the year ended December 31, 2004 from 33% in 2003. We experienced increased demand for almost all of our services, and we also benefited by completing various decommissioning projects on our oil and gas properties. The increased revenue was partially offset by the sale of our construction and fabrication assets in August 2003, which had revenue of approximately $19.0 million in 2003. The increase in demand and decommissioning projects contributed to the improvement in the segment’s gross margin percentage.

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Rental Tools Segment
Revenue for our rental tools segment for the year ended December 31, 2004 was $170.1 million, a 20% increase over 2003. The increase in this segment’s revenue was primarily due to an increased demand for our expanded inventory of downhole rental tool equipment and our continued international expansion, due primarily to the August 2003 acquisition of Premier Oilfield Services. In addition, we benefited from increased bolting, torque and on-site machining work and increased rentals of stabilizers and housing units. The gross margin percentage declined slightly to 66% in the year ended December 31, 2004 from 67% in of 2003 due primarily to a change in the mix of our rental revenue.
Marine Segment
Our marine segment revenue for the year ended December 31, 2004 slightly decreased 1% from 2003 to $69.8 million. The gross margin percentage for the year ended December 31, 2004 remained unchanged at 29%. The fleet’s average dayrate decreased slightly to $6,295 in the year ended December 31, 2004 from $6,306 in 2003, but average utilization increased to 72% for the year ended December 31, 2004 from 66% in 2003. Average fleet dayrates entering 2004 were significantly less than the same period a year ago due to lower demand for liftboats. As liftboat utilization increased throughout the year, we began to experience higher rates, particularly in the third and fourth quarters.
Oil and Gas Segment
Oil and gas revenues were $37.0 million and the gross margin percentage was 42% for the year ended December 31, 2004, compared to revenues of $0.7 million and gross margin percentage of 55% for the year ended December 31, 2003. The increase in revenue is due to the fact that our oil and gas segment began in December 2003 and has benefited from the South Pass 60 acquisition completed in July 2004. The segment was negatively impacted by Hurricane Ivan which shut-in or curtailed production from the South Pass 60 field beginning in mid-September 2004 through late December 2004.
Depreciation, Depletion, Amortization and Accretion
Depreciation, depletion, amortization and accretion increased to $67.3 million in the year ended December 31, 2004 from $48.9 million in 2003. The increase is primarily a result of depletion and accretion related to our oil and gas properties. The increase is also the result of our acquisition of Premier Oilfield Services in August 2003 and capital expenditures during 2003 and 2004.
General and Administrative
General and administrative expenses increased to $110.6 million for the year ended December 31, 2004 from $94.8 million in 2003. The increase is primarily the result of our acquisitions, internal growth and international expansion.
Liquidity and Capital Resources
In the year ended December 31, 2005, we generated net cash from operating activities of $158.4 million as compared to $91.3 million in 2004. Our primary liquidity needs are for working capital, capital expenditures, debt service and acquisitions. Our primary sources of liquidity are cash flows from operations and borrowings under our revolving credit facility. We had cash and cash equivalents of $54.5 million at December 31, 2005 compared to $15.3 million at December 31, 2004.
We made $125.2 million of capital expenditures during the year ended December 31, 2005, of which approximately $68.5 million was used to expand and maintain our rental tool equipment inventory. We also made $19.7 million of capital expenditures in our oil and gas segment and $32.8 million of capital expenditures, inclusive of $6.7 million in progress payments made on the crane as noted below and $5.6 million for the purchase of a 200-foot class liftboat which we were previously operating, to expand and maintain the asset base of our well intervention and marine segments. In addition, we made $4.2 million of capital expenditures on construction and improvements to our facilities.

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In March 2005, we contracted to construct an 880-ton derrick barge to support our decommissioning operations on the Outer Continental Shelf. The contracts are for the construction of a 350-foot barge and crane for a price of approximately $23 million. This amount does not include any future change orders, barge outfitting or mobilization costs. Progress payments were made on the crane in accordance with the terms set forth in the contract. Letters of credit are due on the barge based on contract milestones. The contract price for the barge will be payable upon its delivery and acceptance. We expect the barge to be available in the Gulf of Mexico late in the third quarter of 2006. We intend to utilize it to remove platforms and structures owned by our subsidiary, SPN Resources, LLC, and compete in the Gulf of Mexico construction market for both installation and removal projects. At December 31, 2005, the total amount of progress payments made on the crane was approximately $6.7 million. We also placed a deposit of approximately $0.6 million on an anchor handling tug for the barge. The remaining balance of approximately $5.3 million is expected to be paid in the first quarter of 2006.
We also paid additional consideration for prior acquisitions of $5.3 million in 2005, all of which were capitalized and accrued during 2004.
We have a bank credit facility consisting of a revolving credit facility of $150 million, with an option to increase it to $250 million. Any balance outstanding on the revolving credit facility is due on October 31, 2008. The credit facility bears interest at a LIBOR rate plus margins that depend on the Company’s leverage ratio. As of February 17, 2006, there was no balance outstanding on this credit facility. Indebtedness under the credit facility is secured by substantially all of the Company’s assets, including the pledge of the stock of the Company’s principal subsidiaries. The credit facility contains customary events of default and requires that the Company satisfy various financial covenants. It also limits the Company’s capital expenditures, its ability to pay dividends or make other distributions, make acquisitions, make changes to the Company’s capital structure, create liens, incur additional indebtedness or assume additional decommissioning liabilities which would require supplemental bonding.
We have $17.4 million outstanding at December 31, 2005 in U. S. Government guaranteed long-term financing under Title XI of the Merchant Marine Act of 1936, which is administered by the Maritime Administration (MARAD), for two 245-foot class liftboats. This debt bears an interest rate of 6.45% per annum and is payable in equal semi-annual installments of $405,000 on every June 3rd and December 3rd through June 3, 2027. Our obligations are secured by mortgages on the two liftboats. This MARAD financing also requires that we comply with certain covenants and restrictions, including the maintenance of minimum net worth and debt-to-equity requirements.
We also have outstanding $200 million of 8 7/8% senior notes due 2011. The indenture governing the senior notes requires semi-annual interest payments on every May 15th and November 15th through the maturity date of May 15, 2011. We may redeem the senior notes during the 12-month period commencing May 15, 2006 at 104.438% of the principal amount redeemed. The indenture governing the senior notes contains certain covenants that, among other things, prevent us from incurring additional debt, paying dividends or making other distributions, unless our ratio of cash flow to interest expense is at least 2.25 to 1, except that we may incur debt in addition to the senior notes in an amount equal to 30% of our net tangible assets, which was approximately $208 million at December 31, 2005. The indenture also contains covenants that restrict our ability to create certain liens, sell assets or enter into certain mergers or acquisitions.
The following table summarizes our contractual cash obligations and commercial commitments at December 31, 2005 (amounts in thousands) for our long-term debt (including estimated interest payments), decommissioning liabilities, operating leases and contractual obligations. The decommissioning liability amounts do not give any effect to our contractual right to receive amounts from third parties, which is approximately $31.5 million, when decommissioning operations are performed. We do not have any other material obligations or commitments.

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Description   2006     2007     2008     2009     2010     Thereafter  
 
Long-term debt, including estimated interest payments
   $ 19,670     $ 19,617     $ 19,565     $ 19,513     $ 19,461     $ 229,549  
Decommissioning liabilities
     14,268       26,408       7,294       3,831       13,609       56,499  
Operating leases
     6,360       4,837       2,723       1,667       1,137       14,181  
Derrick barge and tug construction
     21,263       —       —       —       —       —  
     
Total
   $ 61,561     $ 50,862     $ 29,582     $ 25,011     $ 34,207     $ 300,229  
     
We have no off-balance sheet arrangements other than our potential additional consideration that may be payable as a result of the future operating performances of our acquisitions. At December 31, 2005, the maximum additional consideration payable for our prior acquisitions was approximately $2.4 million. These amounts are not classified as liabilities under generally accepted accounting principles and are not reflected in our financial statements until the amounts are fixed and determinable. When amounts are determined, they are capitalized as part of the purchase price of the related acquisition. We do not have any other financing arrangements that are not required under generally accepted accounting principles to be reflected in our financial statements.
We have identified capital expenditure projects that will require approximately $214 million in 2006, exclusive of any acquisitions for, among other things, geographic expansion, the construction of our derrick barge and anchor handling tug, the refurbishment of a 200-foot class liftboat and reserve additions in our oil and gas segment. We believe that our current working capital, cash generated from our operations and availability under our revolving credit facility will provide sufficient funds for our identified capital projects.
We intend to continue implementing our growth strategy of increasing our scope of services through both internal growth and strategic acquisitions. We expect to continue to make the capital expenditures required to implement our growth strategy in amounts consistent with the amount of cash generated from operating activities, the availability of additional financing and our credit facility. Depending on the size of any future acquisitions, we may require additional equity or debt financing in excess of our current working capital and amounts available under our revolving credit facility.
Hedging Activities
We enter into hedging transactions with major financial institutions to secure a commodity price for a portion of our future production and to reduce our exposure to fluctuations in the price of oil. We do not enter into hedging transactions for trading purposes. Crude oil hedges are settled based on the average of the reported settlement prices for West Texas Intermediate crude on the New York Mercantile Exchange (NYMEX) for each month. We had no natural gas hedges as of December 31, 2005 and 2004. We use financially-settled crude oil swaps and zero-cost collars that provide floor and ceiling prices with varying upside price participation. Our swaps and zero-cost collars are designated and accounted for as cash flow hedges.
With a financially-settled swap, the counterparty is required to make a payment to us if the settlement price for any settlement period is below the hedged price for the transaction, and we are required to make a payment to the counterparty if the settlement price for any settlement period is above the hedged price for the transaction. With a zero-cost collar, the counterparty is required to make a payment to us if the settlement price for any settlement period is below the floor price of the collar, and we are required to make a payment to the counterparty if the settlement price for any settlement period is above the cap price for the collar. We recognize the fair value of all derivative instruments as assets or liabilities on the balance sheet. Changes in the fair value of cash flow hedges are recognized, to the extent the hedge is effective, in other comprehensive income until the hedged item is recognized in oil and gas revenues. For the year ended December 31, 2005, hedging settlement payments reduced oil revenues by approximately $10.2 million dollars and gains or losses due to hedge ineffectiveness were not material.
We had the following hedging contracts as of December 31, 2005:

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Crude Oil Positions  
    Instrument   Strike     Volume (Bbls)      
Remaining Contract Term   Type   Price (Bbl)     Daily   Total (Bbls)  
01/06 - 8/06
   Swap   $ 39.45     1,000 - 1,013     274,388  
01/06 - 8/06
   Collar   $ 35.00/$45.60     1,000 - 1,013     274,388  
Recently Issued Accounting Pronouncements
In December 2004, the Financial Accounting Standards Board revised its Statement of Financial Accounting Standards No. 123 (FAS No. 123R), “Accounting for Stock Based Compensation.” Under FAS No. 123R, companies will be required to recognize as expense the estimated fair value of all share-based payments to employees, including the fair value of employee stock options. This expense will be recognized over the period during which the employee is required to provide service in exchange for the award. Pro forma disclosure of the estimated expense impact of such awards is no longer an alternative to expense recognition in the financial statements. FAS No. 123R is effective for public companies in the first annual period beginning after June 15, 2005, and accordingly, we will adopt the provisions of FAS No. 123R effective January 1, 2006. We anticipate using the modified prospective application transition method, which does not include restatement of prior periods. We expect to record approximately $89,000 of compensation expense in 2006 due to the adoption of FAS No. 123R for share-based awards granted prior to January 1, 2006. We expect the effect of the adoption on future share-based awards to be consistent with the disclosure of pro forma net income and earnings per share as displayed in note 1 of our consolidated financial statements included in Item 8 of this Form 10-K.
In May 2005, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 154 (FAS No. 154), “Accounting Changes and Error Corrections.” This Statement replaces APB Opinion No. 20, “Accounting Changes” and FASB Statement No. 3, “Reporting Accounting Changes in Interim Financial Statements.” FAS No. 154 provides guidance on the accounting for and reporting of accounting changes and error corrections. It establishes, unless impracticable, retrospective application as the required method for reporting all changes in accounting principle in the absence of explicit transition requirements of new pronouncements. FAS No. 154 is effective for accounting changes and error corrections made in fiscal years beginning after December 15, 2005.
Item 7A. Quantitative and Qualitative Disclosures about Market Risk
We are exposed to market risks associated with foreign currency fluctuations and changes in interest rates. A discussion of our market risk exposure in financial instruments follows.
Foreign Currency Exchange Rates
Because we operate in a number of countries throughout the world, we conduct a portion of our business in currencies other than the U.S. dollar. The functional currency for most of our international operations is the U.S. dollar, but a portion of the revenues from our foreign operations is paid in foreign currencies. The effects of foreign currency fluctuations are partly mitigated because local expenses of such foreign operations are also generally denominated in the same currency. We continually monitor the currency exchange risks associated with all contracts not denominated in the U.S. dollar. Any gains or losses associated with such fluctuations have not been material.
We do not hold any foreign currency exchange forward contracts and/or currency options. We have not made use of derivative financial instruments to manage risks associated with existing or anticipated transactions. We do not hold derivatives for trading purposes or use derivatives with complex features. Assets and liabilities of our foreign subsidiaries are translated at current exchange rates, while income and expense are translated at average rates for the period. Translation gains and losses are reported as the foreign currency translation component of accumulated other comprehensive income in stockholders’ equity.

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Interest Rates
At December 31, 2005, none of our long-term debt outstanding had variable interest rates, and we had no interest rate risks at that time.
Commodity Price Risk
Our revenue, profitability and future rate of growth partially depends upon the market prices of oil and natural gas. Lower prices may also reduce the amount of oil and gas that can economically be produced.
We use derivative commodity instruments to manage commodity price risks associated with future oil and natural gas production. As of December 31, 2005, we had the following contracts in place:
                         
Crude Oil Positions  
    Instrument   Strike     Volume (Bbls)      
Remaining Contract Term   Type   Price (Bbl)     Daily   Total (Bbls)  
01/06 - 8/06
   Swap   $ 39.45     1,000 - 1,013     274,388  
01/06 - 8/06
   Collar   $ 35.00/$45.60     1,000 - 1,013     274,388  
Our hedged volume as of December 31, 2005 was approximately 50% of our estimated production from proved reserves for the balance of the terms of the contracts. Had these contracts been terminated at December 31, 2005, the estimated loss would have been $6.9 million, net of taxes.
We used a sensitivity analysis technique to evaluate the hypothetical effect that changes in the market value of crude oil would have on the fair value of its existing derivative instruments. Based on the derivative instruments outstanding at December 31, 2005, a 10% increase in the underlying commodity price, increased the net estimated loss associated with the commodity derivative instrument by $1.9 million.

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