Item 3. Legal Proceedings
We are involved in various legal and other proceedings that are incidental to the conduct of our business. We do not believe that any of these proceedings, if adversely determined, would have a material adverse affect on our financial condition, results of operations or cash flows.
Item 4.
Item 4. Submission of Matters to a Vote of Security Holders
None.
Item 4A. Executive Officers of Registrant
Terence E. Hall, age 59, has served as our Chairman of the Board and Chief Executive Officer and as a Director since December 1995. From December 1995 to November 2004, Mr. Hall also served as our President.
Kenneth L. Blanchard, age 55, has served as our President since November 2004, and as our Chief Operating Officer since June 2002. Mr. Blanchard also served as one of our Executive Vice Presidents from December 1995 to November 2004.
Robert S. Taylor, age 50, has served as our Chief Financial Officer since January 1996, as one of our Executive Vice Presidents since September 2004, and as our Treasurer since July 1999. He also served as one of our Vice Presidents from July 1999 to September 2004.
A. Patrick Bernard, age 47, has served as one of our Executive Vice Presidents since September 2004. He served as one of our Vice Presidents from June 2003 until September 2004. From July 1999 until June 2003, Mr. Bernard served as the Chief Financial Officer of our wholly-owned subsidiary International Snubbing Services, L.L.C. and its predecessor company.
L. Guy Cook, III, age 36, has served as one of our Executive Vice Presidents since September 2004. He has also served as a Vice President of our wholly owned subsidiary Superior Energy Services, L.L.C. and its predecessor company since August 2000. He served as our director of Investor Relations from April 1997 to February 2000 and was also responsible for integrating our acquisitions during that time.
James A. Holleman, age 47, has served as one of our Executive Vice Presidents since September 2004. He served as one of our Vice Presidents from July 1999 to September 2004. Since July 1999, Mr. Holleman has served as a Vice President of Superior Energy Services, L.L.C. From 1994 until July 1999, he served as the Chief Operating Officer of Cardinal Services, Inc., which we acquired in July 1999 and is the predecessor to Superior Energy Services, L.L.C.
Gregory L. Miller, age 47, has served as one of our Executive Vice Presidents since September 2004. He also serves as the President of our wholly-owned subsidiary SPN Resources, LLC, which position he has held since April 2003. From January 1991 to April 2003, Mr. Miller served as President and Chief Executive Officer of Optimal Energy, Inc.
Danny R. Young, age 49, has served as one of our Executive Vice Presidents since September 2004. He has also served as Vice President of Health, Safety and Environment and Corporate Services of Superior Energy Services, L.L.C. since January 2002. Prior to joining us, Mr. Young worked for 22 years at BP Amoco, with his most recent position there as manager of Health, Safety and Environmental.
PART II
Item 5.
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Common Stock Information
Our common stock trades on the New York Stock Exchange under the symbol “SPN.” The following table sets forth the high and low sales prices per share of common stock as reported for each fiscal quarter during the periods indicated.
As of February 28, 2005, there were 77,554,214 shares of our common stock outstanding, which were held by 119 record holders.
Dividend Information
We do not plan to pay cash dividends on our common stock. We intend to retain all of the cash our business generates to meet our working capital requirements and fund future growth. In addition, our bank credit facility prevents us from paying dividends or making other distributions to our stockholders.
Equity Compensation Plan Information
Information required by this item with respect to compensation plans under which our equity securities are authorized for issuance will be contained in our definitive proxy statement to be filed pursuant to Regulation 14A and is incorporated herein by reference.
Purchases of Equity Securities
On September 22, 2004, our Board of Directors approved the repurchase of 9,696,627 shares of our common stock from First Reserve Fund VII, Limited Partnership and First Reserve Fund VIII, L.P., pursuant to a private transaction. This transaction, which was publicly announced by us, was consummated on October 19, 2004. The purchase price paid by us to the First Reserve funds was $11.70 per share, for a total aggregate purchase price of approximately $113.4 million.
Item 6.
Item 6. Selected Financial Data
We present below our selected consolidated financial data for the periods indicated. We derived the historical data from our audited consolidated financial statements.
The data presented below should be read together with, and are qualified in their entirety by reference to, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements included elsewhere in this Annual Report. The financial data is in thousands, except per share amounts.
(1) In the year ended December 31, 2004, our subsidiary, SPN Resources, LLC, acquired additional oil and gas properties through the acquisition of interests in 19 offshore Gulf of Mexico leases. Under the terms of these transactions, we paid approximately $10.7 million (net of approximately $5.0 million cash received), acquired the properties and assumed the related decommissioning liabilities.
(2) In the year ended December 31, 2001, we made five acquisitions for $108 million in initial aggregate consideration, of which $2 million was paid with common stock. These acquisitions have been accounted for as purchases, and the results of operations have been included from the respective company’s acquisition date.
(3) In the year ended December 31, 2000, we made six acquisitions for $42.5 million in initial aggregate cash consideration. These acquisitions have been accounted for as purchases, and the results of operations have been included from the respective company’s acquisition date.
(4) Income before cumulative effect of change in accounting principle has been restated for 2000 to include losses due to a refinance of our indebtedness of $1.6 million (net of a $1.0 million income tax benefit). In accordance with Statement of Financial Accounting Standards No. 145 (FAS No. 145), “Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13 and Technical Corrections,” we have reclassified these losses, as they are no longer considered extraordinary items.
(5) In 2001, we changed depreciation methods from the straight-line method to the units of production method on our liftboat fleet. The cumulative effect of this change in accounting principle on prior years resulted in an increase in net income of $2.6 million, net of income taxes of $1.7 million.
Item 7.
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 elsewhere in this Annual Report on Form 10-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 this Annual Report on Form 10-K.
Executive Summary
We are a leading provider of specialized oilfield services and equipment focused on serving the production-related needs of oil and gas companies primarily in the Gulf of Mexico and the drilling-related needs of oil and gas companies in the Gulf of Mexico and select international market areas. We also own and operate, through our subsidiary SPN Resources, LLC, mature oil and gas properties in the Gulf of Mexico. Our business is organized into five segments consisting of well intervention services, marine services, rental tools, other oilfield services and oil and gas operations.
The oil and gas industry remains highly cyclical and seasonal. Activity levels in our four service and rental segments are driven primarily by traditional energy indicators, which include current and expected future commodity prices, drilling rig count in the Gulf of Mexico for services and worldwide for rental tools, oil and gas production levels, and customers’ capital spending allocated for drilling and production, particularly in the Gulf of Mexico.
In 2004, activity levels increased across all of our segments due to:
• increased demand as a result of better market conditions;
• the acquisition of several mature oil and gas properties which yielded higher oil and gas production and utilization for our services and liftboats;
• geographic expansion, primarily in the rental tools segment; and
• further market acceptance of our bundled services strategy which led to additional higher margin, production-related projects.
The acquisition of several mature Gulf of Mexico properties resulted in oil and gas production of approximately 918,000 barrels of oil equivalent Boe, net of royalties, in 2004 as compared to approximately 16,000 Boe in 2003. We incurred significant production downtime from mid-September 2004 until late December 2004 as a result of damage caused by Hurricane Ivan.
The acquisition of mature properties increased the utilization of our assets by providing us with additional decommissioning opportunities. We use our production-related assets to enhance, maintain and extend existing production and, at the end of a property’s economic life, to plug and decommission wells. Because we own and operate the properties, we are able to control when these services are provided and do so in a manner that employs our assets during seasonal downtime and at times we have available assets not otherwise being utilized. Work on our own properties accounted for 14% of the utilization of our well services crews within our well intervention segment for 2004, and 29% and 21% of their utilization for the first and fourth quarters of 2004, respectively.
Another factor impacting our growth in 2004 was our geographic expansion. We now have domestic rental tool operations in Louisiana, Oklahoma, Texas and Wyoming, and international rental tool operations in Venezuela, Trinidad, Mexico, Eastern Canada, the North Sea, the Middle East and West Africa. We also successfully capped several wells in Egypt as part of an ongoing well control project. International revenue in 2004 was a record $87.6 million, a 54% increase from the $56.7 million of international revenue we recorded in 2003.
Finally, in 2004, we performed more bundled services projects on producing wells than we have in past years. Historically, our bundled services were employed on retiring wells following the end of their economic lives. We believe this is due to the use of our bundled services on our own producing wells, as well as a result of improving market conditions and further awareness of our bundled services offering.
We believe we are well positioned to capitalize on one of the most prevalent trends impacting our core shallow water Gulf of Mexico market - the divestment of properties by larger energy producers. The continued maturation of the market has led larger energy producers to sell assets in search of higher returning investments in the deepwater Gulf of Mexico and other developing markets worldwide. As a result, small energy producers are substantially increasing their investment and presence on the Gulf of Mexico Outer Continental Shelf. Our bundled strategy attempts to address these market dynamics and leverage the significant asset base dedicated to our core market. In addition, as large energy producers continue to divest, we believe our financial flexibility and operational experience make us a likely candidate to continue acquiring additional mature producing properties.
Well Intervention Segment
The well intervention segment consists of specialized downhole 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 increased each quarter during 2004 as demand steadily improved throughout the year. In 2004, we benefited from removing and decommissioning our offshore properties. In addition, our coiled tubing, mechanical wireline, plug and abandonment and well control operations grew from 2003 levels. The mechanical wireline operations posted record revenues and operating income in 2004. Our well control operations were involved in a major well control project during the fourth quarter.
Marine Segment
Liftboat operations have relatively high operating leverage, meaning that operating costs are fairly fixed and, therefore, gross margin percentages vary significantly from quarter-to-quarter and year-to-year based on changes in dayrates and utilization levels.
In 2004, liftboat days worked increased almost 2% and the average dayrate for our liftboat fleet was virtually unchanged as compared to 2003. However, the last half of 2004 was stronger than the first half of the year as liftboat days worked were about 5% higher in the third and fourth quarters as compared to the first and second quarters. In addition, the average fleet dayrate was 20% higher during the last six months of the year as compared to the first six months.
Rental Tools Segment
In 2004, our rental tools segment continued to grow through geographic expansion. New locations in Oklahoma, Texas and Wyoming yielded higher revenue and operating income in on-site accommodations, and stabilization and downhole tubulars businesses. Our August 2003 acquisition of Premier Oilfield Services resulted in increased rentals of specialty drill pipe and handling tools in the North Sea, Middle East and West Africa. In addition, we increased rentals of drill pipe, stabilizers and downhole tubulars and other related accessories in Trinidad and Mexico.
Revenue and operating income grew in the first and second quarters before Hurricane Ivan shut down several deepwater Gulf of Mexico projects in the third quarter. As a result, rentals in this market fell sharply and began to resume toward the end of the year. The segment’s gross margin percentage fell slightly as higher margin drill pipe rentals decreased in the third and fourth quarters.
Other Oilfield Services Segment
More than half of this segment’s revenues are derived from our offshore platform and property management business, a labor-intensive business with low margins. Activity for this business increased as the group managed more properties from traditional customers and added properties we acquired in 2004. Environmental services, such as dockside vessel and tank cleaning and non-hazardous oilfield waste treatment, comprise most of the other revenue and operating income in this segment. The increase in the Gulf of Mexico drilling rig count helped increase activity for our environmental services. The segment’s gross margin percentage in 2004 was unchanged from 2003.
Oil and Gas Segment
In December 2003, we began our oil and gas production and sales business. 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, 2004, we had interests in 35 offshore blocks containing 64 structures and 350 productive wells, of which approximately 180 were producing.
Following our acquisition of these properties, SPN Resources will produce and sell the remaining economic oil and gas reserves of these properties. The lease operating expenses for these types of mature properties are typically higher than other properties because of the amount of well intervention service work required to enhance, maintain and extend production. The gross operating margin is also a function of oil and gas prices.
The main objective of this new business segment is to provide additional opportunities for our well intervention services and our platform management businesses. We intend to increase the utilization of our well intervention services by deploying these services on our own properties during periods of downtime.
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 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. We estimated 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 compared these fair value estimates to the determined carrying value of our reporting units. Based on this test, the fair value of the reporting units exceeded the carrying amount, and no impairment loss has been 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 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.
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 leases 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. One of our subsidiaries, 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 then 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 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, 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 five business segments. Oil and gas eliminations represent products and services provided to the oil and gas segment by the Company’s four other segments.
The following discussion analyzes our operating results on a segment basis.
Well Intervention Segment
Revenue for our well intervention segment was $211.8 million for the year ended December 31, 2004, as compared to $187.3 million for the same period in 2003. This segment’s gross margin percentage increased to 42% in the year ended December 31, 2004 from 41% 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. These increases in demand and decommissioning projects contributed to the improvement in the segment’s gross margin percentage.
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.
Other Oilfield Services Segment
Other oilfield services revenue for the year ended December 31, 2004 was $83.9 million, a 17% decrease over the $100.9 million in revenue for 2003. The lower revenue is primarily attributable to the sale of our construction and fabrication assets in August 2003, which had revenue of approximately $19.0 million in 2003. The gross margin percentage remained unchanged at 19% in 2004 and 2003. The decrease in revenue resulted in a $2.6 million operating loss for this segment in 2004.
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.
Comparison of the Results of Operations for the Years Ended December 31, 2003 and 2002
For the year ended December 31, 2003, our revenues were $500.6 million resulting in net income of $30.5 million or $0.41 diluted earnings per share. For the year ended December 31, 2002, our revenues were $443.1 million and our net income was $21.9 million or $0.30 diluted earnings per share. Our increase in revenue and net income is the result of an overall increased demand for most of our services due to increased activity by our customers.
The following table compares our operating results for the years ended December 31, 2003 and 2002. Gross margin is calculated by subtracting cost of services from revenue for each of our five business segments.
The following discussion analyzes our operating results on a segment basis.
Well Intervention Segment
Revenue for our well intervention segment was $187.3 million for the year ended December 31, 2003, as compared to $148.7 million for 2002. This segment’s gross margin percentage increased slightly to 41% in the year ended December 31, 2003 from 37% in 2002. The increase in revenue and gross margin percentage is the result of increased demand for almost all of our services as production-related activity in the Gulf of Mexico increased. Our pumping and stimulation services benefited the most from the increased activity levels in the Gulf of Mexico while our hydraulic workover and well control services benefited from international activity.
Rental Tools Segment
Revenue for our rental tools segment for the year ended December 31, 2003 was $141.4 million, a 14% increase over 2002. The increase in this segment’s revenue was primarily due to an increased demand for our expanded inventory of rental tool equipment and our geographic expansion. During 2003, revenue from international markets grew as we continue to diversify outside of the Gulf of Mexico market area. We acquired Premier Oilfield Services, an Aberdeen, Scotland-based provider of oilfield equipment rentals, in August 2003 to further this diversification. The gross margin percentage decreased slightly to 67% in 2003 from 69% in 2002 due primarily to a change in the mix of the demand for our rental tools.
Marine Segment
Our marine revenue for the year ended December 31, 2003 increased 4% over 2002 to $70.4 million. The fleet’s average dayrate increased to approximately $6,300 in the year ended December 31, 2003 from approximately $5,850 in 2002, and the average utilization decreased to 66% for 2003 from 69% in 2002. The gross margin percentage for the year ended December 31, 2003 decreased to 29% from 34% in 2002. While revenues and the average dayrate increased because of additions of three larger liftboats to the fleet during 2002, a drop-off in utilization and the increased costs of the new liftboats resulted in a lower gross margin percentage. Increased costs, including maintenance and insurance, also contributed to the decline in gross margin percentage.
Other Oilfield Services Segment
Other oilfield services revenue for the year ended December 31, 2003 was $100.9 million, a 2% decrease over the $102.5 million in revenue in 2002. The gross margin percentage decreased slightly to 19% in 2003 from 20% in 2002. The lower revenue is attributable to a decrease in construction and fabrication revenue as the result of the sale of those assets in August 2003, which was partially offset by increases in revenue from our field management services, growth in our oilfield waste treatment business and higher sales of oil spill containment equipment. This segment’s slightly lower gross margin percentage was due to additional costs associated with the sale of our construction and fabrication assets and the growth and expansion of our oilfield waste treatment business, which were partially offset by the increased sales of higher margin oil spill containment equipment.
Oil and Gas Segment
Our oil and gas production did not begin until December 2003, following our initial acquisition of properties in the Gulf of Mexico during that same month. Oil and gas revenues generated during that month were $0.7 million and the gross margin percentage was 55%.
Depreciation, Depletion, Amortization and Accretion
Depreciation and amortization increased to $48.9 million in the year ended December 31, 2003 from $41.6 million in 2002. The increase resulted mostly from our larger asset base as a result of our capital expenditures during 2002 and 2003.
General and Administrative
General and administrative expenses increased to $94.8 million for the year ended December 31, 2003 from $86.2 million in 2002. The increase is primarily the result of our internal growth and the acquisition of Premier Oilfield Services. However, general and administrative expenses as a percentage of revenue remained relatively unchanged at approximately 19% for both periods.
Liquidity and Capital Resources
In the year ended December 31, 2004, we generated net cash from operating activities of $91.3 million. 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 $15.3 million at December 31, 2004 compared to $19.8 million at December 31, 2003.
We made $74.1 million of capital expenditures during the year ended December 31, 2004, of which approximately $49.9 million was used to expand and maintain our rental tool equipment inventory. We also made $19.6 million of capital expenditures to expand and maintain the asset base of our well intervention, marine, other oilfield services and oil and gas segments and $4.6 million on construction and improvements to our facilities. Cash generated from our operations and availability under our revolving credit facility will provide sufficient funds for our identified capital projects.
We paid $24.4 million during the year ended December 31, 2004 as a result of our business acquisitions, which includes additional consideration for prior acquisitions of $21.6 million, of which $10.7 million was earned, capitalized and accrued during 2003, and $10.9 million was earned, capitalized and accrued in 2004. We capitalized and accrued additional consideration of $5.3 million for one prior acquisition, which was paid in the first quarter of 2005.
During 2004, our subsidiary, SPN Resources, LLC, acquired additional oil and gas properties through the acquisition of interests in 19 offshore leases. Under the terms of the transactions, we paid approximately $10.7 million (net of approximately $5.0 million cash received), acquired the properties and assumed the related decommissioning liabilities.
We have a bank credit facility consisting of term loans in an aggregate amount of $38.5 million outstanding at December 31, 2004 and a revolving credit facility of $75 million, none of which was outstanding at December 31, 2004. We amended the credit facility effective June 30, 2004 to extend the maturity date of one of the term loans. As of February 28, 2005, these balances were unchanged and the weighted average interest rate on amounts outstanding under the credit facility was 4.9% per annum. Indebtedness under the credit facility is secured by substantially all of our assets, including the pledge of the stock of our principal subsidiaries. The credit facility contains customary events of default and requires that we satisfy various financial covenants. It also limits our capital expenditures, our ability to pay dividends or make other distributions, make acquisitions, make changes to our capital structure, create liens, incur additional indebtedness or assume additional decommissioning liabilities.
We have $18.2 million outstanding at December 31, 2004 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. 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 $180 million at December 31, 2004. 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, 2004 (amounts in thousands) for our long-term debt (including interest payments), decommissioning liabilities and operating leases. The interest payments on our variable debt were estimated using the rates in effect at December 31, 2004. The decommissioning liability amounts do not give any effect to our contractual right to receive amounts from third parties, which is approximately $38.7 million, when decommissioning operations are performed. We do not have any other material obligations or commitments.
We have no off-balance sheet arrangements other than our potential additional consideration that may be payable as a result of our acquisitions. While the amounts of additional consideration payable depend upon the acquired company’s operating performance and are difficult to predict accurately, the maximum additional consideration that may be payable by us for completed acquisitions is approximately $2.8 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 up to approximately $90 million in 2005, exclusive of any acquisitions. 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, 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 earnings. For the year ended December 31, 2004, hedging settlement payments reduced oil revenues by $1.6 million dollars, and we recognized no gains or losses due to hedge ineffectiveness.
We had the following hedging contracts as of December 31, 2004:
Recently Issued Accounting Pronouncements
During 2004, the Financial Accounting Standards Board issued the following standards, which we intend to adopt as required:
For detailed information regarding any of these pronouncements and the impact thereof on our business, see note 15 to our consolidated financial statements.
Item 7A.
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 made limited 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 leveraged or complex features. Derivative instruments are entered into with creditworthy major financial institutions. 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.
Interest Rates
At December 31, 2004, $38.5 million of our long-term debt had variable interest rates. Based on debt outstanding at December 31, 2004, a 10% increase in variable interest rates would increase our interest expense in the year 2004 by approximately $188,000, while a 10% decrease would decrease our interest expense by approximately $188,000.
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, 2004, we had the following contracts in place:
Our hedged volume as of December 31, 2004 was approximately 47% of our estimated production from proved reserves for the balance of the terms of the contracts. Had these contracts been terminated at December 31, 2004, the estimated loss would have been $1.7 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, 2004, a 10% increase in the underlying commodity price, increased the net estimated loss associated with the commodity derivative instrument by $2.7 million.
Item 8.
Item 8. Financial Statements and Supplementary Data
Management’s Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over our financial reporting, and for performing an assessment of the effectiveness of internal control over our financial reporting as of December 31, 2004. Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Our system of internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of our assets that could have a material effect on the financial statements.
Our management, including our principal executive officer and principal financial officer, performed an assessment of the effectiveness of our internal control over financial reporting as of December 31, 2004 based upon criteria in “Internal Control - Integrated Framework,” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment under the criteria in “Internal Control - Integrated Framework,” our management determined that our internal control over financial reporting was effective as of December 31, 2004.
Our management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2004 has been audited by KPMG LLP, an independent registered public accounting firm, as stated in their report which appears herein.
/s/ Terence E. Hall
/s/ Robert S. Taylor
Terence E. Hall
Robert S. Taylor
Chairman of the Board and
Chief Financial Officer,
Chief Executive Officer
Executive Vice President and Treasurer
Independent Registered Public Accounting Firm Report
The Board of Directors and Stockholders
Superior Energy Services, Inc.:
We have audited the consolidated balance sheets of Superior Energy Services, Inc. and subsidiaries as of December 31, 2004 and 2003, and the related consolidated statements of operations, changes in stockholders’ equity and cash flows for each of the years in the three-year period ended December 31, 2004. In connection with our audit of the consolidated financial statements, we also have audited the accompanying financial statement schedule, “Valuation and Qualifying Accounts,” for the years ended December 31, 2004, 2003 and 2002. These consolidated financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements and financial statement schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Superior Energy Services, Inc. and subsidiaries as of December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2004, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Superior Energy Services, Inc.’s internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 11, 2005 expressed an unqualified opinion on management’s assessment of, and the effective operation of, internal control over financial reporting.
KPMG LLP
New Orleans, Louisiana
March 11, 2005
Independent Registered Public Accounting Firm Report
The Board of Directors and Stockholders
Superior Energy Services, Inc.:
We have audited management’s assessment, included in the accompanying “Management’s Report on Internal Control over Financial Reporting,” that Superior Energy Services, Inc. maintained effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Superior Energy Services, Inc.’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, management’s assessment that Superior Energy Services, Inc. maintained effective internal control over financial reporting as of December 31, 2004, is fairly stated, in all material respects, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Also, in our opinion, Superior Energy Services, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Superior Energy Services, Inc. and subsidiaries as of December 31, 2004 and 2003, and the related consolidated statements of operations, changes in stockholders’ equity and cash flows for each of the years in the three-year period ended December 31, 2004. In connection with our audit of the consolidated financial statements, we also have audited the accompanying financial statement schedule, “Valuation and Qualifying Accounts,” for the years ended December 31, 2004, 2003 and 2002. Our report dated March 11, 2005 expressed an unqualified opinion on those consolidated financial statements and schedule.
KPMG, LLP
New Orleans, Louisiana
March 11, 2005
SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Consolidated Balance Sheets
December 31, 2004 and 2003
(in thousands, except share data)
See accompanying notes to consolidated financial statements.
SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Consolidated Statements of Operations
Years Ended December 31, 2004, 2003 and 2002
(in thousands, except per share data)
See accompanying notes to consolidated financial statements.
SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Consolidated Statements of Changes in Stockholders’ Equity
Years Ended December 31, 2004, 2003 and 2002
(in thousands, except share data)
See accompanying notes to consolidated financial statements.
SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Consolidated Statements of Cash Flows
Years Ended December 31, 2004, 2003 and 2002
(in thousands)
See accompanying notes to consolidated financial statements.
SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2004, 2003 and 2002
(1) Summary of Significant Accounting Policies
(a) Basis of Presentation
The consolidated financial statements include the accounts of the Company. All significant intercompany accounts and transactions are eliminated in consolidation. Certain previously reported amounts have been reclassified to conform to the 2004 presentation.
(b) Business
The Company is a leading provider of specialized oilfield services and equipment focusing on serving the production-related needs of oil and gas companies in the Gulf of Mexico and the drilling-related needs of oil and gas companies throughout the world. The Company provides most of the services, tools and liftboats necessary to maintain, enhance and extend offshore producing wells, as well as plug and abandonment services at the end of their life cycle.
In December 2003, the Company began acquiring oil and gas properties in order to provide additional opportunities for its well intervention and platform management operations in the Gulf of Mexico. The Company intends to continue to acquire mature properties from its customers with modest amounts of estimated remaining productive life, to provide all of its services to the properties to produce any remaining proven oil and gas reserves and to decommission and abandon the properties.
(c) Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
(d) Major Customers and Concentration of Credit Risk
A majority of the Company’s business is conducted with major and independent oil and gas exploration companies. The Company continually evaluates the financial strength of its customers and provides allowances for probable credit losses when deemed necessary but does not require collateral to support the customer receivables.
The market for the Company’s services and products is primarily the offshore oil and gas industry in the Gulf of Mexico. Oil and gas companies make capital expenditures on exploration, drilling and production operations offshore. The level of these expenditures has been characterized by significant volatility.
The Company derives a significant amount of revenue from a small number of major and independent oil and gas companies. In 2004, 2003 and 2002, one customer accounted for approximately 7%, 11%, and 12% of its total revenue, respectively, primarily in the well intervention and other oilfield services segments. The Company’s inability to continue to perform services for a number of large existing customers, if not offset by sales to new or existing customers, could have a material adverse effect on the Company’s business and financial condition.
(e) Cash Equivalents
The Company considers all short-term deposits with a maturity of ninety days or less to be cash equivalents.
(f) Accounts Receivable and Allowances
Trade accounts receivables are recorded at the invoiced amount and do not bear interest. The Company maintains allowances for bad debts and various other adjustments. The allowance for doubtful accounts is based on the Company’s best estimate of the amount of probable uncollectible amounts in existing accounts receivable. The Company determines the allowances based on historical write-off experience and specific identification.
(g) Property, Plant and Equipment
Property, plant and equipment are stated at cost. Most of the Company’s depreciation is computed using the straight-line method over the estimated useful lives of the related assets as follows:
Buildings and improvements
15 to 30 years
Marine vessels and equipment
5 to 25 years
Machinery and equipment
5 to 15 years
Automobiles, trucks, tractors and trailers
2 to 5 years
Furniture and fixtures
3 to 7 years
Marine vessels and oil and gas producing assets are depreciated or depleted based on utilization or units-of-production, because depreciation and depletion occur primarily through use rather than through the passage of time. Units of production depreciation on marine vessels is subject to a minimum amount of depreciation each year.
The Company capitalizes interest on borrowings used to finance the cost of major capital projects during the active construction period. Capitalized interest is added to the cost of the underlying assets and is amortized over the useful lives of the assets. For 2003 and 2002, the Company capitalized approximately $87,000 and $1,066,000, respectively, of interest for various capital expansion projects. There was no interest capitalized during 2004.
Long-lived assets and certain identifiable intangibles are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to future net cash flows expected to be generated by the assets. If such assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds the fair value. Assets to be disposed of are reported at the lower of the carrying amount or fair value less costs to sell.
The Company’s subsidiary, SPN Resources, LLC, acquires oil and natural gas properties and assumes the related decommissioning liabilities. The Company follows the successful efforts method of accounting for its 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.
Oil and gas properties are assessed for impairment in value on a field-by-field basis whenever indicators become evident. The Company uses its 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.
(h) Goodwill
The Company accounts for goodwill and other intangible assets 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. To test for impairment, the Company identifies its reporting units (which are consistent with the Company’s reportable segments) and determines the carrying value of each reporting unit by assigning the assets and liabilities, including goodwill and intangible assets, to the reporting units. The Company then estimates the fair value of each reporting unit and compares it to the reporting unit’s carrying value. Based on this test, the fair value of the reporting units exceeded the carrying amount, and the second step of the impairment test is not required. No impairment loss was recognized in the years ended December 31, 2004, 2003 or 2002. Accumulated amortization of goodwill is $9,151,000 at December 31, 2004 and 2003.
(i) Notes Receivable
Notes receivable consist primarily of commitments from the sellers of oil and gas properties towards the abandonment of the acquired properties. Pursuant to the agreement between the Company and a seller, the Company will invoice the seller agreed upon amounts during the course of decommissioning (abandonment and structure removal). These receivables are recorded at present value, and the related discounts are amortized to interest income, based on the expected timing of the decommissionings.
(j) Other Assets
Other assets consist primarily of debt acquisition costs. Debt acquisition costs are being amortized over the term of the related debt, which is from five to twenty-five years. The amortization of debt acquisition costs, which is classified as interest expense, was approximately $887,000, $1,026,000 and $1,031,000 for the years ended December 31, 2004, 2003 and 2002, respectively. Accumulated amortization of other assets is approximately $4,604,000 and $3,074,000 at December 31, 2004 and 2003, respectively.
(k) Decommissioning Liability
The Company records estimated future decommissioning liabilities related to its oil and gas producing properties pursuant to the provisions of Statement of Financial Accounting Standards No. 143 (FAS No. 143), “Accounting for Asset Retirement Obligations.” FAS No. 143 requires entities to record the fair value of a liability at estimated present value for an asset retirement obligation (decommissioning liabilities) in the period in which it is incurred with a corresponding increase in the carrying amount of the related long-lived asset. Subsequent to initial measurement, the decommissioning liability is required to be accreted each period to present value. The Company’s decommissioning liabilities consist of costs related to the plugging of wells, the removal of facilities and equipment and site restoration on oil and gas properties.
The Company estimates the cost that would be incurred if it contracted an unaffiliated third party to plug and abandon wells, abandon the pipelines, decommission and remove the platforms and pipelines and clear the sites of its oil and gas properties, and uses that estimate to record its proportionate share of the decommissioning liability. In estimating the decommissioning liability, the Company performs detailed estimating procedures, analysis and engineering studies. Whenever practical, the Company utilizes its own equipment and labor services to perform well abandonment and decommissioning work. When the Company performs these services, all recorded intercompany revenues are eliminated in the consolidated
financial statements. The recorded decommissioning liability associated with a specific property is fully extinguished when the property is abandoned. The recorded liability is first reduced by all cash expenses incurred to abandon and decommission the property. If the recorded liability exceeds (or is less than) the Company’s out-of-pocket costs, then the difference is reported as income (or loss) in the period in which the work is performed. The Company reviews the adequacy of its decommissioning liability whenever indicators suggest that the estimated cash flows needed to satisfy the liability have changed materially. The timing and amounts of these cash flows are estimates, and changes to these estimates may result in additional liabilities recorded, which in turn would increase the carrying values of the related oil and gas properties.
SPN Resources purchased its first oil and gas properties and assumed the related decommissioning liabilities in December 2003, thus comparable data for the twelve months ended December 31, 2003 is not material. The following table summarizes the activity for the Company’s decommissioning liability for the twelve months ended December 31, 2004 (amounts in thousands):
(l) Revenue Recognition
Revenue is recognized when services or equipment are provided. The Company contracts for marine, well intervention and environmental projects either on a day rate or turnkey basis, with a majority of its projects conducted on a day rate basis. The Company’s rental tools are leased on a day rate basis, and revenue from the sale of equipment is recognized when the equipment is shipped. Reimbursements from customers for the cost of rental tools that are damaged or lost down-hole are reflected as revenue at the time of the incident. The Company recognizes oil and gas revenue from its interests in producing wells as oil and natural gas is produced and sold from those wells.
(m) Income Taxes
The Company provides for income taxes in accordance with Statement of Financial Accounting Standards No. 109 (FAS No. 109), “Accounting for Income Taxes.” FAS No. 109 requires an asset and liability approach for financial accounting and reporting for income taxes. Deferred income taxes reflect the impact of temporary differences between amounts of assets and liabilities for financial reporting purposes and such amounts as measured by tax laws.
(n) Earnings per Share
Basic earnings per share is computed by dividing income available to common stockholders by the weighted average number of common shares outstanding during the period. Diluted earnings per share is computed in the same manner as basic earnings per share except that the denominator is increased to include the number of additional common shares that could have been outstanding assuming the exercise of stock options and restricted stock units and the potential shares that would have a dilutive effect on earnings per share.
(o) Financial Instruments
The fair value of the Company’s financial instruments of cash, accounts receivable and current maturities of long-term debt approximates their carrying amounts. The fair value of the Company’s long-term debt is approximately $264.2 million at December 31, 2004.
(p) Foreign Currency Translation
Assets and liabilities of the Company’s foreign subsidiaries are translated at current exchange rates, while income and expenses 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.
(q) Stock Based Compensation
The Company accounts for its stock based compensation under the principles prescribed by the Accounting Principles Board’s Opinion No. 25 (Opinion No. 25), “Accounting for Stock Issued to Employees” However, Statement of Financial Accounting Standards No. 123 (FAS No. 123), “Accounting for Stock-Based Compensation” permits the continued use of the intrinsic-value based method prescribed by Opinion No. 25 but requires additional disclosures, including pro forma calculations of earnings and net earnings per share as if the fair value method of accounting prescribed by FAS No. 123 had been applied. No stock based compensation costs from stock options are reflected in net income, as all options granted under those plans had an exercise price equal to the market value of the underlying common stock on the date of grant. Stock compensation costs from the grant of restricted stock units are expensed as incurred (see note 9). The pro forma data presented below is not representative of the effects on reported amounts for future years (amounts are in thousands, except per share amounts).
(r) Hedging Activities
The Company enters into hedging transactions with major financial institutions to secure a commodity price for a portion of future production and to reduce the Company’s exposure to fluctuations in the price of oil. The Company does 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. The Company had no natural gas hedges as of December 31, 2004. The Company uses financially-settled crude oil swaps and zero-cost collars that provide floor and ceiling prices with varying upside price participation. The Company’s 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 the Company if the settlement price for any settlement period is below the hedged price for the transaction, and the Company is 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 the Company if the settlement price for any settlement period is below the floor price of the collar, and the Company is required to make a payment to the counterparty if the settlement price for any settlement period is above the cap price for the collar. The Company recognizes 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 settled and recorded in revenue. For the year ended December 31, 2004, hedging settlement payments reduced oil revenues by $1.6 million dollars. The Company recognized no gains or losses due to hedge ineffectiveness, but any gains or losses resulting from hedge ineffectiveness would be recorded in revenue.
Based upon current market prices, the Company expects to transfer approximately $1.3 million of net deferred losses in accumulated other comprehensive loss as of December 31, 2004 to earnings during the next twelve months when the forecasted transactions actually occur.
(s) Other Comprehensive Income
The following table reconciles the change in accumulated other comprehensive income for the years ended December 31, 2004 and 2003 (amounts in thousands):
(2) Supplemental Cash Flow Information
The following table includes the Company’s supplemental cash flow information for the years ended December 31, 2004, 2003 and 2002 (amounts in thousands):
As the result of a tropical storm, one of the Company’s 200-foot class liftboats sank in the Gulf of Mexico on June 30, 2003. The vessel was declared a total loss and the Company received $8 million of insurance proceeds for the vessel. As a result, the Company recorded a gain from the insurance proceeds of $2.8 million, which is included in other income in the year ended December 31, 2003.
(4) Acquisitions and Dispositions
In December 2004, the Company’s wholly-owned subsidiary, SPN Resources, LLC, acquired additional oil and gas properties at West Delta 79/86 through the acquisition of 100% working interests in seven leases on five shallow water Gulf of Mexico blocks, which included eight platforms and more than 100 wells. Under the terms of the transaction, the Company acquired the properties and assumed the decommissioning liabilities. Concurrently with this transaction, the Company also sold a portion of the behind pipe reserves and exploration rights. The Company retained an overriding royalty interest in any new drill well opportunities identified with the option to participate instead on a well-by-well basis for a working interest. The Company received $3.7 million net cash at closing from the two transactions. The Company preliminarily recorded a decommissioning liability of $29.4 million, and oil and gas producing assets were recorded at their estimated fair value of $25.7 million.
In July 2004, SPN Resources, LLC, acquired additional oil and gas properties at South Pass 60 through the acquisition of nine offshore Gulf of Mexico leases. The purchase included 100% working interest in these nine leases on seven shallow water Gulf of Mexico blocks, nine structures, several pipelines and approximately 125
productive wells. Under the terms of the transaction, the Company paid approximately $15.6 million in cash, acquired the properties and assumed the related decommissioning liabilities. The Company preliminarily recorded receivables of approximately $2.1 million decommissioning liabilities of $39.2 million and oil and gas producing assets were recorded at their estimated fair value of $52.7 million.
In the first quarter of 2004, SPN Resources, LLC, acquired additional oil and gas properties through the acquisition of interests in three offshore Gulf of Mexico leases. Under the terms of the transactions, the Company acquired the properties and assumed the decommissioning liabilities. The Company received $1.2 million cash and will invoice the sellers at agreed upon prices as the decommissioning activities (abandonment and structure removal) are completed. The Company preliminarily recorded notes receivable of $10.4 million and a decommissioning liability of $14.4 million. Oil and gas producing assets were recorded at their estimated fair value of $2.8 million. The pro forma effect of operations of these acquisitions when included as of the beginning of the periods presented was not material to the Company’s Consolidated Statements of Operations and are not included in the table below.
In 2004, the Company acquired two businesses for an aggregate of $2.8 million in cash consideration in order to enhance the products and services offered by its rental tools segment and well intervention segment. Additional consideration, if any, will be based upon the average EBITDA less certain adjustments over a three-year period, and will not exceed $2.8 million in the aggregate for both acquisitions. These acquisitions have been accounted for as purchases and the acquired assets and liabilities have been valued at their estimated fair value. The purchase price preliminarily allocated to net assets was approximately $1.0 million in the aggregate, and the excess purchase price over the fair value of net assets of approximately $1.8 million in the aggregate was allocated to goodwill. The results of operations have been included from the acquisition dates.
In December 2003, SPN Resources acquired oil and gas properties through the acquisition of interests in 24 offshore Gulf of Mexico leases. Under the terms of the transaction, the Company acquired the properties and assumed the decommissioning liability. The Company received a commitment from the seller towards the abandonment of the properties and will invoice the seller at agreed upon prices as the decommissionings are completed. The Company recorded notes receivable of $33.4 million and a decommissioning liability of $38.9 million. Oil and gas producing assets were recorded at their estimated fair value of $5.5 million.
In August 2003, the Company sold its construction-related assets that were included in the other oilfield services segment for $1.25 million. The Company received $312,500 in cash for the sale and a note receivable for the remaining $937,500. There was no gain or loss recorded on the sale. These assets generated approximately $19.0 million and $25.8 million of the Company’s revenues in the years ended December 31, 2003 and 2002, respectively.
In August 2003, the Company acquired Premier Oilfield Services, Ltd. (Premier), an Aberdeen, Scotland-based provider of oilfield equipment rentals, in order to geographically expand the Company’s operations and the rental tool segment. The Company paid $3.4 million in cash consideration, including transaction costs, and an additional $29.0 million to repay Premier’s existing debt, concurrently with the acquisition. The acquisition has been accounted for as a purchase and the acquired assets and liabilities have been valued at their fair values.
The following unaudited pro forma information for the years ended December 31, 2004 and 2003 presents a summary of the consolidated results of operations as if the acquisitions and disposition described above as well as the equity offering described in note 9 had occurred on January 1, 2003, with pro forma adjustments to give effect to depreciation, depletion, interest and certain other adjustments, together with related income tax effects (in thousands, except per share amounts):
The above pro forma information is not necessarily indicative of the results of operations that would have been achieved had the acquisition been effected January 1, 2003.
Most of the Company’s business acquisitions have involved additional contingent consideration based upon a multiple of the acquired companies’ respective average earnings before interest, income taxes, depreciation and amortization expense (EBITDA) over a three-year period from the respective date of acquisition. While the amounts of additional consideration payable depend upon the acquired company’s operating performance and are difficult to predict accurately, the maximum additional consideration payable for the Company’s remaining acquisitions will be approximately $2.8 million. These amounts are not classified as liabilities under generally accepted accounting principles and are not reflected in the Company’s financial statements until the amounts are fixed and determinable. The Company does not have any other financing arrangements that are not required under generally accepted accounting principles to be reflected in its financial statements. When amounts are determined, they are capitalized as part of the purchase price of the related acquisition. In the year ended December 31, 2004, the Company capitalized additional consideration of $16.2 million related to two of its acquisitions, of which $10.9 million was paid during 2004 and $5.3 million was paid in the first quarter of 2005.
(5) Property, Plant and Equipment
A summary of property, plant and equipment at December 31, 2004 and 2003 (in thousands) is as follows:
Amounts of property, plant and equipment leased to third parties at December 31, 2004 and 2003 were not material. Depreciation expense (excluding depletion, amortization and accretion) was approximately $57.1 million, $48.5 million, and $41.2 million for the years ended December 31, 2004, 2003 and 2002, respectively.
(6) Investments in Affiliates
The Company has a 54.3% equity ownership interest in Lamb Energy Services, LLC, a rental tool company. The Company is accounting for its investment under the equity method of accounting, as it does not have voting or operational control of Lamb Energy. Investments in affiliates also include a 50% ownership interest in a company that owns an airplane. At December 31, 2004, the Company’s balance of investments in affiliates was $14.5 million. Included in this balance is approximately $6.4 million of goodwill related to the investment in Lamb Energy. The equity in income from these investments was approximately $1,329,000 and $985,000 for the years ended December 31, 2004 and 2003, respectively, and a loss of approximately $80,000 for the year ended December 31, 2002. The summarized financial information of the aggregate of these entities is not material to the Company’s financial position or results of operations.
(7) Debt
Long-Term Debt
The Company’s long-term debt as of December 31, 2004 and 2003 consisted of the following (in thousands):
The Company has a bank credit facility consisting of term loans in an aggregate amount of $38.5 million outstanding at December 31, 2004, and a revolving credit facility of $75 million, none of which was outstanding at December 31, 2004. The credit facility was amended effective June 30, 2004, to extend the maturity date of one of the term loans. As amended, the term loans require principal payments of $2.8 million each quarter through June 30, 2008. Any balance outstanding on the revolving credit facility is due on August 13, 2006. The credit facility bears interest at a LIBOR rate plus margins that depend on the Company’s leverage ratio. 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. Subsequent to year-end, the Company amended its bank credit facility to permit it to incur additional secured indebtedness of up to $5.0 million. The Company also has letters of credit outstanding of approximately $7.0 million at December 31, 2004, which reduce the borrowing availability under our revolving credit facility. The letters of credit are primarily extended to certain insurance companies to secure our payments.
The Company has $18.2 million outstanding 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. The debt bears an interest rate of 6.45% per annum and is payable in equal semi-annual installments of $405,000, which began December 3, 2002, and matures on June 3, 2027. The Company’s obligations are secured by mortgages on the two liftboats. In accordance with the agreement, the Company is required to comply with certain covenants and restrictions, including the maintenance of minimum net worth and debt-to-equity requirements. This long-term financing ranks equally with the bank credit facility as both are secured by unique assets.
The Company also has outstanding $200 million of 8 7/8% unsecured senior notes due 2011. The indenture governing the notes requires semi-annual interest payments, on every November 15th and May 15th through the maturity date of May 15, 2011. The indenture governing the senior notes contains certain covenants that, among other things, prevents the Company from incurring additional debt, paying dividends or making other distributions, unless its ratio of cash flow to interest expense is at least 2.25 to 1, except that the Company may incur debt in addition to the senior notes in an amount equal to 30% of its net tangible assets as defined, which was approximately $180 million at December 31, 2004. The indenture also contains covenants that restrict the Company’s ability to create certain liens, sell assets, or enter into certain mergers or acquisitions.
Annual maturities of long-term debt for each of the five fiscal years following December 31, 2004 are as follows (in thousands):
(8) Income Taxes
The components of income tax expense (benefit) for the years ended December 31, 2004, 2003 and 2002 are as follows (in thousands):
Income tax expense differs from the amounts computed by applying the U.S. Federal income tax rate of 35% to income before income taxes as follows (in thousands):
The significant components of deferred income taxes at December 31, 2004 and 2003 are as follows (in thousands):
The net deferred tax assets reflect management’s estimate of the amount that will be realized from future profitability and the reversal of taxable temporary differences that can be predicted with reasonable certainty. A valuation allowance is recognized if it is more likely than not that at least some portion of any deferred tax asset will not be realized.
As of December 31, 2004, the Company has not established a valuation reserve for its deferred tax assets. The Company believes that it is more likely than not that the tax assets will be realized because of the reversal of accelerated tax depreciation and future taxable income.
As of December 31, 2004, the Company has an estimated $5.5 million net operating loss carryforward, which is available to reduce future Federal taxable income with expiration dates from 2008 through 2023, an estimated $1.7 million alternative minimum tax credit carryforward, and an estimated $5.3 million foreign tax credit carryforward with expiration dates from 2011 through 2014. As of December 31, 2004, the Company also has various state net operating loss carryforwards of an estimated $65 million with expiration dates from 2013 through 2017.
As of December 31, 2004, the Company has not provided United States tax expense on earnings of its foreign subsidiaries, since the Company has reinvested or expects to reinvest the undistributed earnings indefinitely. As of December 31, 2004, the undistributed earnings of the Company’s foreign subsidiaries were approximately $11.7 million. If these earnings are repatriated to the United States in the future, additional tax provisions may be required.
The American Jobs Creation Act of 2004 was passed on October 22, 2004. This legislation allows, under certain conditions, a one-time tax deduction of 85% of certain foreign earnings that are repatriated prior to the end of the Company’s fiscal 2005 year. The deduction would result in a 5.25% federal tax rate on the repatriated earnings. The Company is in the process of evaluating whether any of its foreign earnings will qualify for the temporary deduction and whether it will repatriate all or a portion of any qualifying foreign earnings.
As of December 31, 2004, the Company has not determined whether earnings will be repatriated or an estimate of the possible United States federal and state income tax expense related to any potential repatriation. The Company expects to make its decision prior to December 31, 2005.
(9) Stockholders’ Equity
In October 2004, the Company sold 9,696,627 shares of common stock that generated net proceeds (before any exercise of the underwriters’ over-allotment option) of approximately $113 million, after deducting underwriting discounts and commissions and the estimated offering expenses. The Company used the net proceeds to repurchase 9,696,627 shares of its common stock from First Reserve Fund VII, Limited Partnership and First Reserve Fund
VIII, L.P. The shares repurchased by the Company from the First Reserve funds were retired immediately upon repurchase. In November 2004, an additional 1,454,494 shares of the Company’s common stock were issued pursuant to the exercise of the underwriters’ over-allotment option generating net proceeds of approximately $17 million, after deducting underwriting discounts and commissions.
In 2004, the Superior Energy Services, Inc. 2004 Directors Restricted Stock Units Plan was approved by the Company’s stockholders. This plan provides each non-employee director is granted a number of restricted stock units having an aggregate value of $30,000, with the exact number of units determined by dividing $30,000 by the fair market value of the Company’s common stock on the day of the annual stockholders’ meeting. In addition, upon any person’s initial election or appointment as an eligible director, other than at an annual stockholders’ meeting, such person will receive a pro forma number of restricted stock units based on the number of full calendar months between the date of grant and the first anniversary of the previous annual stockholders’ meeting. A restricted stock unit represents the right to receive from the Company, within 30 days of the date the participant ceases to serve on the Board, one share of the Company’s common stock. As a result of this plan, 9,783 restricted stock units are outstanding at December 31, 2004.
In March 2002, the Company sold 4.2 million shares of common stock. The offering generated net proceeds to the Company of approximately $39 million.
The Company maintains various stock incentive plans, including the 2002 Stock Incentive Plan (2002 Incentive Plan), the 1999 Stock Incentive Plan (1999 Incentive Plan) and the 1995 Stock Incentive Plan (1995 Incentive Plan), as amended. These plans provide long-term incentives to the Company’s key employees, including officers and directors, consultants and advisers (Eligible Participants). Under the 2002 Incentive Plan, the 1999 Incentive Plan and the 1995 Incentive Plan, the Company may grant incentive stock options, non-qualified stock options, restricted stock, stock awards or any combination thereof to Eligible Participants for up to 1,400,000 shares, 5,929,327 shares and 1,900,000 shares, respectively, of the Company’s common stock. The Compensation Committee of the Company’s Board of Directors establishes the term and the exercise price of any stock options granted under the 2002 Incentive Plan, provided the exercise price may not be less than the fair value of the common share on the date of grant. All of the options which have been granted under the 1995 Stock Incentive Plan are vested.
A summary of stock options granted under the incentive plans for the years ended December 31, 2004, 2003 and 2002 is as follows:
A summary of information regarding stock options outstanding at December 31, 2004 is as follows:
(10) Profit-Sharing Plan
The Company maintains a defined contribution profit-sharing plan for employees who have satisfied minimum service and age requirements. Employees may contribute up to 75% of their earnings to the plans. The Company provides a discretionary match, not to exceed 5% of an employee’s salary. The Company made contributions of approximately $1.7 million, $1.6 million and $1.7 million, in 2004, 2003 and 2002, respectively.
The Company began a nonqualified defined contribution deferred compensation plan in the fourth quarter of 2004. The plan allows certain eligible employees to defer up to 75% of their salary and up to 100% of their bonus compensation to the plan. The Company maintains the assets and has a liability recorded equal to the earnings deferrals and investment income. At December 31, 2004, the asset and liability related to this plan were not material.
(11) Commitments and Contingencies
The Company leases certain office, service and assembly facilities under operating leases. The leases expire at various dates over the next several years. Total rent expense was approximately $4.2 million in 2004, $2.3 million in 2003 and $3.0 million in 2002. Future minimum lease payments under non-cancelable leases for the five years ending December 31, 2005 through 2009 and thereafter are as follows: $5,047,000, $3,887,000, $2,639,000, $1,415,000, $517,000 and $13,735,000, respectively. Future minimum lease payments receivable under non-cancelable sub-leases for the five years ending December 31, 2005 through 2008 are as follows: $576,000, $535,000, $472,000 and $39,000, respectively.
From time to time, the Company is involved in litigation arising out of operations in the normal course of business. In management’s opinion, the Company is not involved in any litigation, the outcome of which would have a material effect on its financial position, results of operations or liquidity.
(12) Segment Information
Business Segments
The Company has modified its segment disclosure by breaking out its oil and gas operations from the well intervention segment. This change better reflects the impact of the oil and gas operations and service work created for the other segments, as well as how the Company’s management evaluates its results of operations. The Company’s reportable segments are now as follows: well intervention, marine, rental tools, other oilfield services and oil and gas. The first four segments offer products and services within the oilfield services industry. The well intervention segment provides plug and abandonment services, coiled tubing services, well pumping and stimulation services, data acquisition services, gas lift services, electric wireline services, hydraulic drilling and workover services, well control services and mechanical wireline services that perform a variety of ongoing maintenance and repairs to producing wells, as well as modifications to enhance the production capacity and life span of the well. The marine segment operates liftboats for oil and gas production facility maintenance, construction operations and platform removals, as well as production service activities. The rental tools segment rents and sells specialized equipment for use with onshore and offshore oil and gas well drilling, completion, production and workover
activities. The other oilfield services segment provides contract operations and maintenance services, interconnect piping services, sandblasting and painting maintenance services, transportation and logistics services, offshore oil and gas cleaning services, oilfield waste treatment services, dockside cleaning of items, including supply boats, cutting boxes, and process equipment, and manufactures and sells drilling instrumentation and oil spill containment equipment. The oil and gas segment acquires mature oil and gas reserves and produces these reserves for as long as economically viable. Then, the Company’s other segments provide decommissioning services. The Company’s first acquisition of oil and gas properties was in December 2003.
The accounting policies of the reportable segments are the same as those described in Note 1 of these Notes to the Consolidated Financial Statements. The Company evaluates the performance of its operating segments based on operating profits or losses. Segment revenues reflect direct sales of products and services for that segment, and each segment records direct expenses related to its employees and its operations. Identifiable assets are primarily those assets directly used in the operations of each segment.
Summarized financial information concerning the Company’s segments as of December 31, 2004, 2003 and 2002 and for the years then ended is shown in the following tables (in thousands):
Geographic Segments
The Company attributes revenue to various countries based on the location of where services are performed or the destination of the sale of products. Long-lived assets consist primarily of property, plant, and equipment and are attributed to various countries based on the physical location of the asset at a given fiscal year-end. The Company’s information by geographic area is as follows (amounts in thousands):
(13) Interim Financial Information (Unaudited)
The following is a summary of consolidated interim financial information for the years ended December 31, 2004 and 2003 (amounts in thousands, except per share data):
(14) Supplementary Oil and Natural Gas Disclosures - (Unaudited)
The Company’s December 31, 2004 estimates of proved reserves are based on reserve reports prepared by DeGolyer and MacNaughton, independent petroleum engineers. The estimates of proved reserves at December 31, 2003 are based on internal reports. Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” natural gas and crude oil reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. This data may also change substantially over time as a result of multiple factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions to existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the significance of the subjective decisions required and variances in available data for various reservoirs make these estimates generally less precise than other estimates presented in connection with financial statement disclosures. Proved reserves are estimated quantities of natural gas, crude oil 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 developed reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
The following table sets forth the Company’s net proved reserves, including the changes therein, and proved developed reserves:
The Company filed no reserve estimates with any Federal authorities or agencies during 2004.
Costs incurred for oil and natural gas property acquisition and development activities for the years ended December 31, 2004 and 2003 are as follows (in thousands):
The asset retirement liability amounts incurred do not give any effect to the Company’s contractual right to receive amounts from third parties, which is approximately $38.7 million, when decommissioning operations are completed.
Standardized Measure of Discounted Future Net Cash Flows Relating to Reserves
The following information has been developed utilizing procedures prescribed by Statement of Financial Accounting Standards No. 69 (FAS No. 69), “Disclosure about Oil and Gas Producing Activities.” It may be useful for certain comparative purposes, but should not be solely relied upon in evaluating the Company or its performance. Further, information contained in the following table should not be considered as representative of realistic assessments of future cash flows, nor should the Standardized Measure of Discounted Future Net Cash Flows be viewed as representative of the current value of the Company.
The Company believes that the following factors should be taken into account in reviewing the following information: (1) future costs and selling prices will probably differ from those required to be used in these calculations; (2) due to future market conditions and governmental regulations, actual rates of production achieved in future years may vary significantly from the rate of production assumed in the calculations; (3) selection of a 10%
discount rate is arbitrary and may not be reasonable as a measure of the relative risk inherent in realizing future net oil and gas revenues; and (4) future net revenues may be subject to different rates of income taxation.
Under the Standardized Measure, future cash inflows were estimated by applying period end oil and natural gas prices adjusted for differentials provided by the Company. Future cash inflows were reduced by estimated future development, abandonment and production costs based on period-end costs in order to arrive at net cash flow before tax. Future income tax expense has been computed by applying period-end statutory tax rates to aggregate future net cash flows, reduced by the tax basis of the properties involved and tax carryforwards. Use of a 10% discount rate is required by FAS No. 69.
The Company’s management does not rely solely upon the following information in making investment and operating decisions. Such decisions are based upon a wide range of factors, including estimates of probable as well as proved reserves and varying price and cost assumptions considered more representative of a range of possible economic conditions that may be anticipated.
The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves is as follows (in thousands):
A summary of the changes in the standardized measure of discounted future net cash flows applicable to proved oil and natural gas reserves for the years ended December 31, 2004 and 2003 is as follows (in thousands):
The December 31, 2004 amount was estimated by DeGolyer and MacNaughton using a period-end crude NYMEX price of $43.46 per barrel (Bbl), a Henry Hub gas price of $6.19 per million British Thermal units, and price differentials provided by the Company. The December 31, 2003 amount was estimated by the Company using a period end oil price of $32.55 per Bbl and $6.14 per thousand cubic feet (Mcf) for natural gas. The Company had no oil and gas holdings prior to 2003. Spot prices as of February 28, 2005 were $6.73 per million British Thermal units for natural gas and $51.75 per Bbl for crude oil.
In November 2004, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 151 (FAS No. 151), “Inventory Costs.” The Statement amends Accounting Research Bulletin No. 43 (ARB No. 43), “Inventory Pricing,” to clarify the accounting for abnormal amounts of idle facility expense, freight, handling costs, and wasted material. ARB No. 43 previously stated that these costs must be “so abnormal as to require treatment as current-period charges.” FAS No. 151 requires that those items be recognized as current-period charges regardless of whether they meet the criterion of “so abnormal.” In addition this Statement requires that allocation of fixed production overhead to the costs of conversion be based on the normal capacity of the production facilities. This Statement is effective for inventory costs incurred during fiscal years beginning after June 15, 2005, with earlier application permitted for fiscal years beginning after the issue date of the Statement. The Company does not believe the adoption of FAS No. 151 will have a significant impact on its financial condition and results of operations.
In December 2004, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 152 (FAS No. 152), “Accounting for Real Estate Time-Sharing Transactions - An Amendment of FASB Statements No. 66 and 67,” which states that the guidance for incidental operations and costs incurred to sell real estate projects does not apply to real estate time-sharing transactions. The Company does not believe the adoption of FAS No. 152 will have a significant impact on its financial condition and results of operations.
In December 2004, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 153 (FAS No. 153), “Exchanges of Nonmonetary Assets - An Amendment of APB Opinion No. 29.” APB Opinion No. 29, “Accounting for Nonmonetary Transactions,” is based on the opinion that exchanges of nonmonetary assets should be measured based on the fair value of the assets exchanged. FAS No. 153 amends Opinion No. 29 to eliminate the exception for nonmonetary exchanges of similar productive assets and replaces it with a general exception for exchanges of nonmonetary assets whose results are not expected to significantly change the future cash flows of the entity. The Company does not believe the adoption of FAS No. 153 will have a significant impact on our financial condition and results of operations.
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.” The revision establishes standards for the accounting of transactions in which an entity exchanges its equity instruments for goods or services, particularly transactions in which an entity obtains employee services in share-based payment transactions. The revised statement requires a public entity to measure the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award. That cost is to be recognized over the period during which the employee is required to provide service in exchange for the award. Changes in fair value during the requisite service period are to be recognized as compensation cost over that period. In addition, the revised statement amends Statement of Financial Accounting Standards No. 95, “Statement of Cash Flows,” to require that excess tax benefits be reported as a financing cash flow rather than as a reduction of taxes paid. The provisions of the revised statement are effective for financial statements issued for the first interim or annual reporting period beginning after June 15, 2005, with early adoption encouraged. If the Company had adopted this Statement during 2004, it would have recognized $7 million of additional expense, net of tax.
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A.
Item 9A. Controls and Procedures
Disclosure Controls and Procedures
Our management has established and maintains a system of disclosure controls and procedures to provide reasonable assurances that information required to be disclosed by us in the reports that we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms, and that such information is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as
appropriate, to allow timely decisions regarding required disclosure based closely on the definition of “disclosure controls and procedures” in Rule 13a-15(e) of the Securities Exchange Act of 1934. We also have investments in certain unconsolidated entities. As we do not control or manage these entities, our disclosure controls and procedures with respect to such entities are necessarily substantially more limited than those we maintain with respect to our consolidated subsidiaries.
Management’s Annual Report on Internal Control Over Financial Reporting
As of December 31, 2004, our management, including our principal executive officer and principal financial officer, evaluated the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(e) of the Securities Exchange Act of 1934. Based on this evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures as of December 31, 2004 are effective in providing reasonable assurance that the information required to be disclosed by us in reports filed under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Management’s report and the independent registered public accounting firm’s attestation report are included in Item 8 under the captions “Management’s Report on Internal Control over Financial Reporting” and “Independent Registered Public Accounting Firm’s Report,” and are incorporated herein by reference.
Changes in Internal Control Over Financial Reporting
There has been no change in our internal control over financial reporting during the quarter ended December 31, 2004 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
Item 9B.
Item 9B. Other Information
None.
PART III
Item 10.
Item 10. Directors and Executive Officers of the Registrant
Information required by this item will be contained in our definitive proxy statement to be filed pursuant to Regulation 14A and is incorporated herein by reference.
Item 11.
Item 11. Executive Compensation
Information required by this item will be contained in our definitive proxy statement to be filed pursuant to Regulation 14A and is incorporated herein by reference.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Information required by this item will be contained in our definitive proxy statement to be filed pursuant to Regulation 14A and is incorporated herein by reference.
Item 13.
Item 13. Certain Relationships and Related Transactions
Information required by this item will be contained in our definitive proxy statement to be filed pursuant to Regulation 14A and is incorporated herein by reference.
Item 14.
Item 14. Principal Accountant Fees and Services
Information required by this item will be contained in our definitive proxy statement to be filed pursuant to Regulation 14A and is incorporated herein by reference.
PART IV
Item 15.
Item 15. Exhibits and Financial Statement Schedules
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Schedule II Valuation and Qualifying Accounts
Years Ended December 31, 2004, 2003 and 2002
(in thousands)
E-1
E-2
E-3