Patterson-UTI Energy - 10-Q quarterly report FY

 

     Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes þ     No o

      Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

     Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yes o     No þ

     Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.

     154,617,905 shares of common stock, $0.01 par value, as of October 30, 2008

     The following unaudited consolidated financial statements include all adjustments which are, in the opinion of management, necessary for a fair statement of the results for the interim periods presented.

CONSOLIDATED BALANCE SHEETS
(unaudited, in thousands, except share data)

The accompanying notes are an integral part of these unaudited consolidated financial statements.

CONSOLIDATED STATEMENTS OF INCOME
(unaudited, in thousands, except per share amounts)

The accompanying notes are an integral part of these unaudited consolidated financial statements.

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY
(unaudited, in thousands)

The accompanying notes are an integral part of these unaudited consolidated financial statements.

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY
(unaudited, in thousands)

The accompanying notes are an integral part of these unaudited consolidated financial statements.

CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited, in thousands)

The accompanying notes are an integral part of these unaudited consolidated financial statements.

     The unaudited interim consolidated financial statements include the accounts of Patterson-UTI Energy, Inc. (the “Company”) and its wholly-owned subsidiaries. All significant intercompany accounts and transactions have been eliminated. The Company has no controlling financial interests in any entity that is not a wholly-owned subsidiary and which would require consolidation.

     The unaudited interim consolidated financial statements have been prepared by management of the Company pursuant to the rules and regulations of the Securities and Exchange Commission. Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been omitted pursuant to such rules and regulations, although the Company believes the disclosures included either on the face of the financial statements or herein are sufficient to make the information presented not misleading. In the opinion of management, all adjustments which are of a normal recurring nature considered necessary for a fair statement of the information in conformity with accounting principles generally accepted in the United States have been included. The Unaudited Consolidated Balance Sheet as of December 31, 2007, as presented herein, was derived from the audited balance sheet of the Company, but does not include all disclosures required by accounting principles generally accepted in the United States of America. These unaudited consolidated financial statements should be read in conjunction with the consolidated financial statements and related notes included in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2007.

     The U.S. dollar is the functional currency for all of the Company’s operations except for its Canadian operations, which use the Canadian dollar as their functional currency. The effects of exchange rate changes are reflected in accumulated other comprehensive income, which is a separate component of stockholders’ equity.

     The Company provides a dual presentation of its net income per common share in its Unaudited Consolidated Statements of Income: Basic net income per common share (“Basic EPS”) and diluted net income per common share (“Diluted EPS”). Basic EPS excludes dilution and is computed by dividing net income by the weighted average number of common shares outstanding during the period excluding nonvested restricted stock. Diluted EPS is based on the weighted-average number of common shares outstanding plus the impact of dilutive instruments, including stock options, restricted stock and stock unit awards using the treasury stock method. The following table presents information necessary to calculate net income per share for the three and nine months ended September 30, 2008 and 2007 as well as potentially dilutive securities excluded from the weighted average number of diluted common shares outstanding, as their inclusion would have been anti-dilutive during the three and nine months ended September 30, 2008 and 2007 (in thousands, except per share amounts):

     Reclassifications — Certain reclassifications have been made to the 2007 consolidated financial statements in order for them to conform with the 2008 presentation.

     The results of operations for the three and nine months ended September 30, 2008 are not necessarily indicative of the results to be expected for the full year.

     The Company recognizes the cost of share-based awards under the fair-value method. The Company uses share-based awards to compensate employees and non-employee directors. All awards have been equity instruments in the form of stock options, restricted stock awards or stock unit awards and have included service and, in certain cases, performance conditions. The Company issues shares of common stock when vested stock option awards are exercised, when restricted stock awards are granted and when stock unit awards vest.

     Stock Options.  The Company estimates the grant date fair values of stock options using the Black-Scholes-Merton valuation model (“Black-Scholes”). Volatility assumptions are based on the historic volatility of the Company’s common stock over the most recent period equal to the expected term of the options as of the date the options are granted. The expected term assumptions are based on the Company’s experience with respect to employee stock option activity. Dividend yield assumptions are based on the expected dividends at the time the options are granted. The risk-free interest rate assumptions are determined by reference to United States Treasury yields. No stock options were granted in the three month periods ended September 30, 2008 and 2007. Weighted-average assumptions used to estimate the grant date fair values for stock options granted in the nine month periods ended September 30, 2008 and 2007 follow:

     Stock option activity from January 1, 2008 to September 30, 2008 follows:

     Restricted Stock.  For all restricted stock awards to date, shares of common stock were issued when granted. Nonvested shares are subject to forfeiture for failure to fulfill service conditions and, in certain cases, performance conditions. Nonforfeitable cash dividends are paid on nonvested restricted shares.

     Restricted stock activity from January 1, 2008 to September 30, 2008 follows:

     Stock Units.  For all stock unit awards to date, shares of common stock are not issued until the awards vest. Awards are subject to forfeiture for failure to fulfill service conditions. Nonforfeitable cash dividend equivalents are paid on nonvested stock units.

     Stock unit activity from January 1, 2008 to September 30, 2008 follows:

     Property and equipment consisted of the following at September 30, 2008 and December 31, 2007 (in thousands):

     The Company’s revenues, operating profits and identifiable assets are primarily attributable to four business segments: (i) contract drilling of oil and natural gas wells, (ii) pressure pumping services, (iii) drilling and completion fluid services and (iv) the investment, on a working interest basis, in oil and natural gas properties. Each of these segments represents a distinct type of business based upon the type and nature of services and products offered. These segments have separate management teams which report to the Company’s chief operating decision maker and have distinct and identifiable revenues and expenses. Separate financial data for each of our four business segments is provided in the table below (in thousands):

     Goodwill is evaluated at least annually to determine if the fair value of recorded goodwill has decreased below its carrying value. At December 31, 2007 the Company performed its annual goodwill evaluation and determined no adjustment to impair goodwill was necessary. Goodwill at both September 30, 2008 and December 31, 2007 includes $86.2 million in the Contract Drilling segment and $10.0 million in the Drilling and Completion Fluids segment.

     Accrued expenses consisted of the following at September 30, 2008 and December 31, 2007 (in thousands):

     Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations,” requires that the Company record a liability for the estimated costs to be incurred in connection with the abandonment of oil and natural gas properties in the future. The following table describes the changes to the Company’s asset retirement obligations during the nine months ended September 30, 2008 and 2007 (in thousands):

     The Company has an unsecured revolving line of credit (“LOC”) with a maximum borrowing capacity of $375 million. Interest is paid on outstanding LOC balances at a floating rate ranging from LIBOR plus 0.625% to 1.0% or the prime rate at the Company’s election. Any outstanding borrowings must be repaid at maturity on December 16, 2009. This arrangement includes various fees, including a commitment fee on the average daily unused amount (0.15% at September 30, 2008). There are customary restrictions and covenants associated with the LOC. Financial covenants provide for a maximum debt to capitalization ratio and a minimum interest coverage ratio. The Company does not expect that the restrictions and covenants will impact its ability to operate or react to opportunities that might arise. As of September 30, 2008, the Company had no borrowings outstanding under the LOC. However, the Company had $58.5 million in letters of credit outstanding and as a result, the Company had available borrowing capacity of approximately $316 million at September 30, 2008.

     Commitments — As of September 30, 2008, the Company maintained letters of credit in the aggregate amount of $58.5 million for the benefit of various insurance companies as collateral for retrospective premiums and retained losses which could become payable under the terms of the underlying insurance contracts. These letters of credit expire at various times during the calendar year and are typically renewed annually. As of September 30, 2008, no amounts had been drawn under the letters of credit.

     As of September 30, 2008, the Company had commitments to purchase approximately $308 million of major equipment.

     The Company is party to various legal proceedings arising in the normal course of its business. The Company does not believe that the outcome of these proceedings, either individually or in the aggregate, will have a material adverse effect on its financial condition, results of operations or cash flows.

     Cash Dividends — The Company paid cash dividends as follows:

     On October 29, 2008, the Company’s Board of Directors approved a cash dividend on its common stock in the amount of $0.16 per share to be paid on December 30, 2008 to holders of record as of December 12, 2008. The amount and timing of all future dividend payments, if any, is subject to the discretion of the Company’s Board of Directors and will depend upon business conditions, results of operations, financial condition, terms of the Company’s credit facilities and other factors.

     On August 1, 2007, the Company’s Board of Directors approved a stock buyback program (“Program”), authorizing purchases of up to $250 million of the Company’s common stock in open market or privately negotiated transactions. During the nine months ended September 30, 2008, the Company purchased 2,002,047 shares of common stock under the Program at a cost of $50.4 million. As of September 30, 2008, the Company had authority remaining under the Program to purchase approximately $129 million of the Company’s outstanding common stock. Shares purchased under the Program are accounted for as treasury stock.

     The Company purchased 152,235 shares of treasury stock from employees during the nine months ended September 30, 2008 to provide employees with the funds necessary to satisfy payroll tax withholding obligations upon the vesting of shares of restricted stock. The purchases were made at fair market value and the total purchase price for these shares was approximately $4.5 million. These purchases were made pursuant to the terms of the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan and not pursuant to the Program.

     The Company adopted Financial Accounting Standards Board (“FASB”) Interpretation No. 48,Accounting for Uncertainty in Income Taxes – an interpretation of FASB Statement No. 109 (“FIN 48”), on January 1, 2007. FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements and prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. As of September 30, 2008, the Company had no unrecognized tax benefits. In connection with the adoption of FIN 48, the Company established a policy to account for interest and penalties with respect to income taxes as operating expenses. As of September 30, 2008, the tax years ended December 31, 2005 through December 31, 2007 are open for examination by U.S. taxing authorities. As of September 30, 2008, the tax years ended December 31, 2004 through December 31, 2007 are open for examination by Canadian taxing authorities.

     In September 2006, the FASB issued Statement No. 157, Fair Value Measurements (“FAS 157”). FAS 157 defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurement. The initial application of FAS 157 is limited to financial assets and liabilities and became effective on January 1, 2008 for the Company. The impact of the initial application was not material. The Company will adopt FAS 157 on a prospective basis for nonfinancial assets and liabilities that are not measured at fair value on a recurring basis on January 1, 2009. The application of FAS 157 to the Company’s nonfinancial assets and liabilities will primarily be limited to assets acquired and liabilities assumed in a business combination, asset retirement obligations and asset impairments, including goodwill and long-lived assets. This application of FAS 157 is not expected to have a material impact to the Company.

     In December 2007, the FASB issued Statement No. 141(R), Business Combinations (“FAS 141(R)”) and Statement No. 160, Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51 (“FAS 160”). FAS 141(R) is a revision of Statement No. 141, Business Combinations, and calls for significant changes from current practice in accounting for business combinations. FAS 141(R) is effective for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. FAS 160 amends ARB 51 to establish accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. FAS 160 is effective for fiscal years beginning on or after December 15, 2008. Both FAS 141(R) and FAS 160 will be effective for the Company beginning the quarter ending March 31, 2009. The application of FAS 141(R) and FAS 160 are not expected to have a material impact to the Company.

     In June 2008, the FASB issued FASB Staff Position No. EITF 03-6-1, Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities (“FSP EITF 03-6-1”). FSP EITF 03-6-1 clarifies that share-based payment awards that entitle their holders to receive nonforfeitable dividends before vesting should be considered participating securities and, as such, should be included in the calculation of basic earnings-per-share using the two-class method. Certain of the Company’s share-based payment awards entitle the holders to receive nonforfeitable dividends and the application of the provisions of FSP EITF 03-6-1 may have the effect of reducing basic and diluted earnings-per-share by an immaterial amount. FSP EITF 03-6-1 is effective for financial

statements issued for fiscal years beginning after December 15, 2008, as well as interim periods within those years. Once effective, all prior-period earnings-per-share data presented must be adjusted retrospectively to conform with the provisions of FSP EITF 03-6-1. FSP EITF 03-6-1 will be effective for the Company beginning in the quarter ending March 31, 2009 and early application is not permitted.

     Management Overview — We are a leading provider of contract services to the North American oil and natural gas industry. Our services primarily involve the drilling, on a contract basis, of land-based oil and natural gas wells and, to a lesser extent, we provide pressure pumping services and drilling and completion fluid services. In addition to the aforementioned contract services, we also invest, on a working interest basis, in oil and natural gas properties. For the three and nine months ended September 30, 2008 and 2007, our operating revenues consisted of the following (dollars in thousands):

     We provide our contract services to oil and natural gas operators in many of the oil and natural gas producing regions of North America. Our contract drilling operations are focused in various regions of Texas, New Mexico, Oklahoma, Arkansas, Louisiana, Mississippi, Alabama, Colorado, Utah, Wyoming, Montana, North Dakota, South Dakota, Pennsylvania and Western Canada, while our pressure pumping services are focused primarily in the Appalachian Basin. Our drilling and completion fluids services are provided to operators offshore in the Gulf of Mexico and on land in Texas, Southeastern New Mexico, Oklahoma and the Gulf Coast region of Louisiana. The oil and natural gas properties in which we hold working interests are primarily located in West and South Texas, Southeastern New Mexico, Utah and Mississippi.

     Typically, the profitability of our business is most readily assessed by two primary indicators in our contract drilling segment: our average number of rigs operating and our average revenue per operating day. During the third quarter of 2008, our average number of rigs operating was 276 per day compared to 243 in the third quarter of 2007. Our average revenue per operating day was $19,620 in the third quarter of 2008 compared to $19,150 in the third quarter of 2007. Our consolidated net income for the third quarter of 2008 increased by $10.6 million or 11% as compared to the third quarter of 2007. This increase in consolidated net income was primarily due to our contract drilling segment experiencing an increase in the average number of rigs operating, partially offset by reduced profitability in our pressure pumping segment in the third quarter of 2008 as compared to the third quarter of 2007.

     Our revenues, profitability and cash flows are highly dependent upon prevailing prices for natural gas and, to a lesser extent, oil. During periods of improved commodity prices, the capital spending budgets of oil and natural gas operators tend to expand, which results in increased demand for our contract services. Conversely, in periods when these commodity prices deteriorate, the demand for our contract services generally weakens and we experience downward pressure on pricing for our services. During recent months, there has been substantial volatility and a decline in oil and natural gas prices. There has also been substantial uncertainty in the capital markets and access to credit is uncertain. Due to these conditions, certain of our customers may begin to curtail their drilling programs which would result in a decrease in demand for our contract services. Furthermore, certain of our customers could experience an inability to pay suppliers, including us, in the event they are unable to access the capital markets to fund their business operations. Our operations are also highly impacted by competition, the availability of excess equipment, labor issues and various other factors which are more fully described as “Risk Factors” included as Item 1A in our Annual Report on Form 10-K for the fiscal year ended December 31, 2007.

     We believe that the liquidity reflected in our balance sheet as of September 30, 2008, which includes approximately $333 million in working capital (including $25.0 million in cash and cash equivalents) and approximately $316 million available under a $375 million line of credit, provides us with the ability to build new equipment, make improvements to our equipment, expand into new regions, pursue acquisition opportunities, pay cash dividends and survive downturns in our industry.

     Commitments and Contingencies — As of September 30, 2008, we maintained letters of credit in the aggregate amount of $58.5 million for the benefit of various insurance companies as collateral for retrospective premiums and retained losses which could become payable under the terms of the underlying insurance contracts. These letters of credit expire at various times during each calendar year and are typically renewed annually. As of September 30, 2008, no amounts had been drawn under the letters of credit.

     As of September 30, 2008, we had commitments to purchase approximately $308 million of major equipment.

     Trading and Investing — We have not engaged in trading activities that include high-risk securities, such as derivatives and non-exchange traded contracts. We invest cash primarily in highly liquid, short-term investments such as overnight deposits and money market accounts.

     Description of Business — We conduct our contract drilling operations in Texas, New Mexico, Oklahoma, Arkansas, Louisiana, Mississippi, Alabama, Colorado, Utah, Wyoming, Montana, North Dakota, South Dakota, Pennsylvania and Western Canada. As of

September 30, 2008, we had approximately 350 currently marketable land-based drilling rigs. We provide pressure pumping services to oil and natural gas operators primarily in the Appalachian Basin. These services consist primarily of well stimulation and cementing for completion of new wells and remedial work on existing wells. We provide drilling fluids, completion fluids and related services to oil and natural gas operators offshore in the Gulf of Mexico and on land in Texas, Southeastern New Mexico, Oklahoma and the Gulf Coast region of Louisiana. Drilling and completion fluids are used by oil and natural gas operators during the drilling process to control pressure when drilling oil and natural gas wells. We also invest, on a working interest basis, in oil and natural gas properties.

     The North American land drilling industry has experienced periods of downturn in demand at various times during the last decade. During these periods, there have been substantially more drilling rigs available than necessary to meet demand. As a result, drilling contractors have had difficulty sustaining profit margins during the downturn periods.

     In addition to adverse effects that future declines in demand could have on us, ongoing factors which could continue to adversely affect utilization rates and pricing, even in an environment of high oil and natural gas prices and increased drilling activity, include:

     As a result of an increase in drilling activity and increased prices for drilling services in 2005 and 2006, construction of new drilling rigs increased significantly in that time period. The addition of new drilling rigs to the market resulted in excess capacity compared to demand, and construction of new drilling rigs moderated in 2007. With an increase in demand in 2008, we believe that further construction of new drilling rigs has again increased. Recent decreases in prices of natural gas and oil are likely to reduce both the demand for our services and construction of new drilling rigs. We cannot predict either the future level of demand for our contract drilling services or future conditions in the oil and natural gas contract drilling business.

     In addition to established accounting policies, our consolidated financial statements are impacted by certain estimates and assumptions made by management. No changes in our critical accounting policies have occurred since the filing of the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2007.

     As of September 30, 2008, we had working capital of $333 million including cash and cash equivalents of $25.0 million. For the nine months ended September 30, 2008, our sources of cash flow included:

     During the nine months ended September 30, 2008, we used $68.3 million to pay dividends on our common stock, $54.9 million to repurchase our common stock, $50.0 million to repay borrowings under our line of credit, and $329 million:

     We paid cash dividends during the nine months ended September 30, 2008 as follows:

     On October 29, 2008, our Board of Directors approved a cash dividend on our common stock in the amount of $0.16 per share to be paid on December 30, 2008 to holders of record as of December 12, 2008. The amount and timing of all future dividend payments, if any, is subject to the discretion of the Company’s Board of Directors and will depend upon business conditions, results of operations, financial condition, terms of our credit facilities and other factors.

     On August 1, 2007, our Board of Directors approved a stock buyback program (“Program”), authorizing purchases of up to $250 million of our common stock in open market or privately negotiated transactions. During the nine months ended September 30, 2008, we purchased 2,002,047 shares of common stock under the Program at a cost of $50.4 million. As of September 30, 2008, we had authority remaining under the Program to purchase approximately $129 million of our outstanding common stock. Shares purchased under the Program are accounted for as treasury stock.

     We have an unsecured revolving line of credit with a maximum borrowing capacity of $375 million. Interest is paid on outstanding LOC balances at a floating rate ranging from LIBOR plus 0.625% to 1.0% or the prime rate at our election. Any outstanding borrowings must be repaid at maturity on December 16, 2009. As of September 30, 2008, we had no borrowings outstanding under our $375 million revolving line of credit. However, we had $58.5 million in letters of credit outstanding and as a result, we had available borrowing capacity of approximately $316 million at September 30, 2008.

     We believe that the current level of cash, short-term investments and borrowing capacity available under our revolving line of credit, together with cash generated from operations, should be sufficient to meet our capital needs. From time to time, acquisition opportunities are evaluated. The timing, size or success of any acquisition and the associated capital commitments are unpredictable. Should opportunities for growth requiring capital arise, we believe we would be able to satisfy these needs through a combination of working capital, cash generated from operations, our existing credit facility, additional debt or equity financing. However, there can be no assurance that such capital will be available on reasonable terms, if at all.

     The following tables summarize operations by business segment for the three months ended September 30, 2008 and 2007:

     Revenues and direct operating costs increased in the third quarter of 2008 compared to the third quarter of 2007 primarily as a result of an increase in the number of operating days and to a lesser extent as a result of increases in the average revenue and average direct operating costs per operating day. Operating days increased in the third quarter of 2008 compared to the third quarter of 2007 due to increased demand for our contract drilling services. Significant capital expenditures have been incurred to build new drilling rigs, to modify and upgrade our existing drilling rigs and to acquire additional related equipment such as drill pipe, drill collars, engines, fluid circulating systems, rig hoisting systems and safety enhancement equipment.

     The number of jobs completed decreased in the third quarter of 2008 compared to the third quarter of 2007 as we and our customers increased our focus on the emerging development of unconventional reservoirs in the Appalachian Basin and the larger jobs associated therewith. As a result of this focus on unconventional reservoirs we experienced a decrease in smaller traditional pressure pumping jobs, which resulted in an overall decrease in the number of total jobs. Revenues and direct operating costs increased as a result of increases in the average revenue and average direct operating costs per job. Increased average revenue per job was due to an increase in larger jobs being driven by demand for services associated with unconventional reservoirs as discussed above. Average direct operating costs per job increased as a result of increases in compensation, maintenance and the cost of materials used in our operations, as well as an increase in larger jobs. Selling, general and administrative expense increased primarily as a result of expenses to support the expanding operations of the pressure pumping segment. Significant capital expenditures have been incurred to add capacity, expand our areas of operation and modify and upgrade existing equipment. The increase in depreciation expense is a result of the capital expenditures discussed above.

     Revenues increased in the third quarter of 2008 compared to the third quarter of 2007 due to increased sales both on land and offshore in the Gulf of Mexico, as well as increased pricing for certain products. Direct operating costs increased due to increased sales as well as increases in the costs of raw materials, including barite ore. Direct operating costs in the third quarter of 2008 also include approximately $650,000 in losses associated with damage suffered as a result of hurricanes.

     Revenues increased due to higher average sales prices of oil and natural gas. This increase was partially offset by decreases in the average net daily production of oil and natural gas and by the elimination of well operations revenue due to the sale in the fourth quarter of 2007 of the operating responsibilities associated with oil and natural gas wells. Average net daily oil and natural gas production decreased primarily due to production declines. The increase in direct operating costs was primarily due to an increase in seismic costs incurred in the third quarter of 2008, as well as increased production taxes and other production costs. Selling, general and administrative expenses decreased in the third quarter of 2008 due to the sale of operating responsibilities mentioned above and the resulting elimination of headcount in our oil and natural gas production and exploration segment. Depreciation, depletion and

impairment expense in the third quarter of 2008 includes approximately $1.6 million incurred to impair certain oil and natural gas properties compared to approximately $1.9 million incurred to impair certain oil and natural gas properties in the third quarter of 2007. Depletion expense decreased approximately $614,000 due to lower production of oil and natural gas and higher commodity prices.

     Other operating expenses increased $650,000 due to an increase in bad debt expense in the third quarter of 2008. Embezzlement recoveries in the third quarter of 2007 consists of cash received from a court-appointed receiver.

     The following tables summarize operations by business segment for the nine months ended September 30, 2008 and 2007:

     Revenues and direct operating costs increased in the first nine months of 2008 compared to the first nine months of 2007 primarily as a result of an increase in the number of operating days. Average revenue per operating day decreased in the first nine months of 2008 while average direct operating costs per operating day increased in the same period. The increase in average direct operating costs per operating day includes costs incurred during 2008 in activating drilling rigs. Significant capital expenditures have been incurred to build new drilling rigs, to modify and upgrade our drilling rigs and to acquire additional related equipment such as drill pipe, drill collars, engines, fluid circulating systems, rig hoisting systems and safety enhancement equipment. The increase in depreciation expense was a result of the capital expenditures discussed above.

     The number of jobs completed decreased in 2008 compared to 2007 as we and our customers increased our focus on the emerging development of unconventional reservoirs in the Appalachian Basin and the larger jobs associated therewith. As a result of this focus on unconventional reservoirs we experienced a decrease in smaller traditional pressure pumping jobs, which resulted in an overall decrease in the number of total jobs. Revenues and direct operating costs increased as a result of an increase in the average revenue and average direct operating costs per job. Increased average revenue per job was due to an increase in larger jobs being driven by demand for services associated with unconventional reservoirs as discussed above. Average direct operating costs per job

increased as a result of increases in compensation, maintenance and the cost of materials used in our operations, as well as an increase in larger jobs. Selling, general and administrative expense increased primarily as a result of expenses to support the expanding operations of the pressure pumping segment. Significant capital expenditures have been incurred to add capacity, expand our areas of operation and modify and upgrade existing equipment. The increase in depreciation expense is a result of the capital expenditures discussed above.

     Revenues increased in the first nine months of 2008 compared to the first nine months of 2007 due to increased sales both on land and offshore in the Gulf of Mexico, as well as increased pricing for certain products. Direct operating costs increased due to increased sales as well as increases in the costs of raw materials, including barite ore. Direct operating costs in 2008 also include approximately $650,000 in losses associated with damage suffered as a result of hurricanes. Direct operating costs in 2007 include a reduction of approximately $1.3 million related to a recovery received on an insurance claim.