Patterson-UTI Energy - 10-Q quarterly report FY

 

(Exact name of registrant as specified in its charter)

     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 has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 Regulation S-T (section 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). 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:

     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.

     153,613,685 shares of common stock, $0.01 par value, as of July 31, 2009

     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.

(unaudited, in thousands, except share data)

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

(unaudited, in thousands, except per share data)

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

(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. Except for wholly-owned subsidiaries, the Company has no controlling financial interests in any entity 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, 2008, as presented herein, was derived from the audited consolidated 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, 2008. The results of operations for the three and six months ended June 30, 2009 are not necessarily indicative of the results to be expected for the full year.

     The U.S. dollar is the functional currency for all of the Company’s operations except for its Canadian operations, which uses the Canadian dollar as its 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 has performed an evaluation of subsequent events through August 4, 2009 at the time of issuance of the unaudited consolidated financial statements.

     The Company provides a dual presentation of its net income (loss) per common share in its Unaudited Consolidated Statements of Income: Basic net income (loss) per common share (“Basic EPS”) and diluted net income (loss) per common share (“Diluted EPS”). The Company adopted the provisions of 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”) in the quarter ended March 31, 2009. FSP EITF 03-6-1 clarifies that share-based payment awards that entitle their holders to receive non-forfeitable dividends before vesting should be considered participating securities and, as such, should be included in the calculation of earnings-per-share using the two-class method. All earnings per share data presented for the three and six months ended June 30, 2008 has been adjusted retrospectively to conform with the provisions of FSP EITF 03-6-1. The impact of this retrospective application was to reduce Basic EPS for the three months ended June 30, 2008 by $0.01 and to reduce Basic EPS and Diluted EPS for the six months ended June 30, 2008 by $0.01.

     Basic EPS excludes dilution and is computed by first allocating earnings between common stockholders and holders of non-vested shares of restricted stock. Basic EPS is then determined by dividing the earnings attributable to common stockholders by the weighted average number of common shares outstanding during the period, excluding non-vested shares of restricted stock.

     Diluted EPS is based on the weighted average number of common shares outstanding plus the dilutive effect of potential common shares, including stock options, non-vested shares of restricted stock and restricted stock units. The dilutive effect of stock options and restricted stock units is determined based on the treasury stock method. The dilutive effect of non-vested shares of restricted stock is based on the more dilutive of the treasury stock method or the two-class method, assuming a reallocation of undistributed earnings to common stockholders after considering the dilutive effect of potential common shares other than non-vested shares of restricted stock.

     The following table presents information necessary to calculate net income (loss) per share for the three and six months ended June 30, 2009 and 2008 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 six months ended June 30, 2009 and 2008 (in thousands, except per share amounts):

     The Company recognizes the cost of share-based awards under the fair-value-based method. The Company uses share-based awards to compensate employees and non-employee directors. All share-based awards have been equity instruments in the form of stock options, restricted stock or restricted stock units and have included service and, in certain cases, performance conditions. The Company issues shares of common stock when vested stock options are exercised, when restricted stock is granted and when restricted stock units 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. Weighted-average assumptions used to estimate the grant date fair values for stock options granted in the three and six month periods ended June 30, 2009 and 2008 follow:

     Stock option activity from January 1, 2009 to June 30, 2009 follows:

     Restricted Stock. For all restricted stock awards to date, shares of common stock were issued when the awards were made. Non-vested shares are subject to forfeiture for failure to fulfill service conditions and, in certain cases, performance conditions. Non-forfeitable dividends are paid on non-vested shares of restricted stock. For restricted stock awards made prior to 2008, the Company used the “graded-vesting” attribution method to recognize periodic compensation cost over the vesting period. For restricted stock awards made in 2008 and thereafter, the Company uses the straight-line method to recognize periodic compensation cost over the vesting period.

     Restricted stock activity from January 1, 2009 to June 30, 2009 follows:

     Restricted Stock Units. For all restricted stock unit awards made to date, shares of common stock are not issued until the units vest. Restricted stock units are subject to forfeiture for failure to fulfill service conditions. Non-forfeitable cash dividend equivalents are paid on non-vested restricted stock units.

     Restricted stock unit activity from January 1, 2009 to June 30, 2009 follows:

     Property and equipment consisted of the following at June 30, 2009 and December 31, 2008 (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. The results of operations in these segments are regularly reviewed by the chief operating decision maker for purposes of determining resource allocation and assessing performance. 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. For purposes of impairment testing, goodwill is evaluated at the reporting unit level. The Company’s reporting units for impairment testing have been determined to be its operating segments.

     As of June 30, 2009 and December 31, 2008 the Company had goodwill of $86.2 million, all in its contract drilling reporting unit. In the event that market conditions remain weak, the Company may be required to record an impairment of goodwill in its contract drilling reporting unit in the future, and such impairment could be material.

     Accrued expenses consisted of the following at June 30, 2009 and December 31, 2008 (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. This liability is included in the caption “Other” in the liabilities section of the Company’s consolidated balance sheet. The following table describes the changes to the Company’s asset retirement obligations during the six months ended June 30, 2009 and 2008 (in thousands):

     The Company entered into an unsecured revolving line of credit (“LOC”) on March 20, 2009 with a maximum borrowing capacity of $220 million, including a letter of credit sublimit of $150 million and a swing line sublimit of $40 million. In addition, the aggregate borrowing and letter of credit capacity under the LOC may, subject to the terms and conditions set forth therein

including the receipt of additional commitments from lenders, be increased up to a maximum amount not to exceed $450 million. On June 19, 2009, the Company entered into a Commitment Increase and Joinder Agreement to increase the maximum borrowing capacity to $240 million.

     Interest is paid on the outstanding principal amount of LOC borrowings at a floating rate based on, at the Company’s election, LIBOR or a base rate. The margin on LIBOR loans ranges from 3.00% to 4.00% and the margin on base rate loans ranges from 2.00% to 3.00%, based on the Company’s debt to capitalization ratio. At June 30, 2009, the margin on LIBOR loans would have been 3.00% and the margin on base rate loans would have been 2.00%. Any outstanding borrowings must be repaid at maturity on January 31, 2012 and letters of credit may remain in effect up to six months after such maturity date. This LOC facility includes various fees, including a commitment fee on the actual daily unused commitment (the commitment fee rate was 1.00% at June 30, 2009).

     The Company incurred line of credit issuance costs of approximately $6.2 million during the six months ended June 30, 2009 in connection with the LOC. These costs are being amortized over the contractual term of the LOC as an adjustment to interest expense.

     There are customary representations, warranties, 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 June 30, 2009, the Company had no borrowings outstanding under the LOC. The Company had $46.3 million in letters of credit outstanding at June 30, 2009 and, as a result, had available borrowing capacity of approximately $194 million at that date. Each domestic subsidiary of the Company has unconditionally guaranteed the existing and future obligations of the Company and each other guarantor under the LOC and related loan documents, as well as obligations of the Company and its subsidiaries under any interest rate swap contracts that may be entered into with lenders party to the LOC.

     Commitments — As of June 30, 2009, the Company maintained letters of credit in the aggregate amount of $46.3 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 June 30, 2009, no amounts had been drawn under the letters of credit.

     As of June 30, 2009, the Company had commitments to purchase approximately $154 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 during the six months ended June 30, 2008 and 2009 as follows:

     On July 29, 2009, the Company’s Board of Directors approved a cash dividend on its common stock in the amount of $0.05 per share to be paid on September 30, 2009 to holders of record as of September 15, 2009. The amount and timing of all future dividend payments, if any, is subject to the discretion of the 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 six months ended June 30, 2009, the Company purchased 3,324 shares of its common stock under the Program at a cost of approximately $46,000. As of June 30, 2009, the Company is authorized to purchase approximately $113 million of the Company’s outstanding common stock under the Program. Shares purchased under the Program are accounted for as treasury stock.

     The Company purchased 85,817 shares of stock from employees during the six months ended June 30, 2009 on dates that corresponded with the vesting of restricted stock. These shares were purchased at fair market value to provide employees with the funds necessary to satisfy payroll tax withholding obligations and have been accounted for as treasury stock. The total purchase price for these shares was approximately $1.1 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.

     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 was limited to financial assets and liabilities and became effective on January 1, 2008 for the Company. The impact of the initial application of FAS 157 was not material. On January 1, 2009, the Company adopted FAS 157 on a prospective basis for non-financial assets and liabilities that are not measured at fair value on a recurring basis. The application of FAS 157 to the Company’s non-financial assets and liabilities is primarily 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 has not had a material impact on 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 non-controlling 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 became effective for the Company on January 1, 2009. The application of FAS 141(R) and FAS 160 did not have a material impact on 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 non-forfeitable 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 non-forfeitable dividends. 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 and became effective for the Company on January 1, 2009. The impact of the adoption of FSP EITF 03-6-1 is discussed in Note 1.

     In December 2008, the SEC issued a Final Rule, Modernization of Oil and Gas Reporting (“Final Rule”). The Final Rule revises certain oil and gas reporting disclosures in Regulation S-K and Regulation S-X under the Securities Act of 1933, as amended (the “Securities Act”) and the Securities Exchange Act of 1934, as amended (the “Exchange Act”), as well as Industry Guide 2. The amendments are designed to modernize and update oil and gas disclosure requirements to align them with current practices and changes in technology. The disclosure requirements are effective for registration statements filed on or after January 1, 2010 and for annual financial statements filed on or after December 31, 2009. The Company is currently evaluating the impact that the Final Rule may have on its consolidated financial statements.

     In April 2009, the FASB issued FASB Staff Position No. 157-4, Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly (“FSP 157-4”). FSP 157-4 provides additional guidance for determining whether a market for a financial asset is not active and a transaction is not distressed for fair value measurements under FAS 157. The provisions of this FSP are effective for financial statements issued for interim and annual periods ending after June 15, 2009 and became effective for the Company in the quarter ended June 30, 2009. The adoption of FSP 157-4 did not have a material impact on the Company.

     In April 2009, the FASB issued FASB Staff Position No. 107-1 and APB No. 28-1, Interim Disclosures about Fair Value of Financial Instruments (“FSP 107-1”). This FSP increases the frequency of fair value disclosures as required by FAS 107, Disclosures about Fair Value of Financial Instruments, from annual only to quarterly reporting periods. The provisions of this FSP are effective for financial statements issued for interim and annual periods ending after June 15, 2009 and became effective for the Company in the quarter ended June 30, 2009. The adoption of FSP 107-1 did not have a material impact on the Company.

     In June 2009, the FASB issued Statement of Financial Accounting Standards No. 167, Amendments to FASB Interpretation No. 46(R) (“FAS 167”). FAS 167 retains the scope of FASB Interpretation No. 46(R) with the addition of entities previously considered qualifying special-purpose entities and requires ongoing reassessments of whether an enterprise is the primary beneficiary of a variable interest entity. Before this Statement, FASB Interpretation No. 46(R) required reconsideration of whether an enterprise is the primary beneficiary of a variable interest entity only when specific events occurred. FAS 167 is effective as of the beginning of each

reporting entity’s first annual reporting period that begins after November 15, 2009, for interim periods within that first annual reporting period, and for interim and annual reporting periods thereafter and will become effective for the Company on January 1, 2010. The adoption of FAS 167 is not expected to have a material impact on the Company.

     In June 2009, the FASB issued Statement of Financial Accounting Standards No. 168, The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles — a replacement of FASB Statement No. 162 (“FAS 168”). On the effective date of FAS 168, the FASB Accounitng Standards Codification (“Codification”) will become the source of authoritative U.S. generally accepted accounting principles. Following FAS 168, the FASB will not issue new standards in the form of Statements, FASB Staff Positions or EITF Abstracts. Instead, it will issue Accounting Standards Updates to update the Codification. FAS 168 is effective for financial statements issued for interim and annual periods ending after September 15, 2009 and will be effective for the Company in the quarter ending September 30, 2009. The adoption of FAS 168 will not have a material impact on the Company.

     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 six months ended June 30, 2009 and 2008, 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, Arizona, Utah, Wyoming, Montana, North Dakota, South Dakota, Pennsylvania, West Virginia 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, New Mexico, Oklahoma and Louisiana. The oil and natural gas properties in which we hold interests are primarily located in Texas, New Mexico, Mississippi and Louisiana.

     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 second quarter of 2009, our average number of rigs operating was 63 compared to 244 in the second quarter of 2008. Our average number of rigs operating during the second quarter of 2009 included approximately seven rigs under term contracts that earned standby revenues of $7.5 million. Rigs on standby earn a discounted dayrate since they do not have crews and have lower costs. Additionally, we recognized $901,000 of revenues during the second quarter of 2009 from the early termination of term contracts. Our average revenue per operating day was $17,780 in the second quarter of 2009 compared to $18,740 in the second quarter of 2008. We had a consolidated net loss of $17.7 million for the second quarter of 2009 compared to consolidated net income of $81.4 million for the second quarter of 2008. This decrease was primarily due to our contract drilling segment experiencing a significant decrease in the average number of rigs operating as compared to the second quarter of 2008.

     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 generally 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. Since reaching a peak in 2008, there has been a significant decline in oil and natural gas prices. During this time there has also been a substantial deterioration in the global economic environment. As part of this deterioration, there has been substantial uncertainty in the capital markets and access to financing has been reduced. Due to these conditions, our customers have reduced or curtailed their drilling programs, which has resulted in a decrease in demand for our services, as evidenced by the decline in our monthly average of rigs operating from a high of 283 in October 2008 to 60 in June 2009. Furthermore, these factors could result in certain of our customers experiencing an inability to pay suppliers, including us, if they are not able to access capital to fund their operations. We are also highly impacted by competition, the availability of excess equipment, labor issues and various other factors that could materially adversely affect our business, financial condition, cash flows and results of operations. Please see “Risk Factors” included as Item 1A in our Annual Report on Form 10-K for the fiscal year ended December 31, 2008.

     We believe that the liquidity shown on our balance sheet as of June 30, 2009, which includes approximately $230 million in working capital (including $168 million in cash and cash equivalents) and approximately $194 million available under our current $240 million line of credit, together with cash expected to be generated from operations, should provide us with sufficient ability to fund our current plans to build new equipment, make improvements to our existing equipment, expand into new regions, pay cash dividends and survive the current downturn in our industry.

     Commitments and Contingencies — As of June 30, 2009, we maintained letters of credit in the aggregate amount of $46.3 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 June 30, 2009, no amounts had been drawn under the letters of credit.

     As of June 30, 2009, we had commitments to purchase approximately $154 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, Arizona, Utah, Wyoming, Montana, North Dakota, South Dakota, Pennsylvania, West Virginia and western Canada. As of June 30, 2009, we had approximately 350 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, New Mexico, Oklahoma and 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 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 and, at times, have incurred losses during the downturn periods.

     In addition to adverse effects that declines in demand have had or 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 recent years prior to the current downturn, construction of new drilling rigs increased significantly. The addition of new drilling rigs to the market and the recent decrease in demand has resulted in excess capacity. 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, 2008.

     As of June 30, 2009, we had working capital of $230 million, including cash and cash equivalents of $168 million. For the six months ended June 30, 2009, our sources of cash flow included $355 million from operating activities.

     During the six months ended June 30, 2009, we used $15.3 million to pay dividends on our common stock, $6.2 million to pay issuance costs related to our LOC and $247 million:

     We paid cash dividends during the six months ended June 30, 2009 as follows:

     On July 29, 2009, our Board of Directors approved a cash dividend on our common stock in the amount of $0.05 per share to be paid on September 30, 2009 to holders of record as of September 15, 2009. The amount and timing of all future dividend payments, if any, is subject to the discretion of the 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 six months ended June 30, 2009, we purchased 3,324 shares of our common stock under the Program at a cost of approximately $46,000. As of June 30, 2009, we are authorized to purchase approximately $113 million of our outstanding common stock under the Program. Shares purchased under the Program have been accounted for as treasury stock.

     We have an unsecured revolving line of credit with a maximum borrowing and letter of credit capacity of $240 million. Interest is paid on the outstanding principal amount of borrowings under the revolving line of credit at a floating rate based on, at our election, LIBOR or a base rate. The margin on LIBOR loans ranges from 3.00% to 4.00% and the margin on base rate loans ranges from 2.00% to 3.00%, based on our debt to capitalization ratio. Any outstanding borrowings must be repaid at maturity on January 31, 2012 and letters of credit may remain in effect up to six months after such maturity date. As of June 30, 2009, we had no borrowings outstanding under this revolving line of credit. We had $46.3 million in letters of credit outstanding at June 30, 2009 and, as a result, had available borrowing capacity of approximately $194 million at such date.

     We believe that the current level of cash, short-term investments and borrowing capacity available under our current revolving line of credit, together with cash expected to be generated from operations, should be sufficient to meet our current 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, borrowing capacity under our existing LOC or 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 June 30, 2009 and 2008:

     Revenues and direct operating costs decreased in the second quarter of 2009 compared to the second quarter of 2008 primarily as a result of a decrease in the number of operating days. The decrease in operating days was due to decreased demand largely caused by lower commodity prices for natural gas and oil. Our average number of rigs operating during the second quarter of 2009 included an average of approximately seven rigs that earned standby revenues of $7.5 million. Rigs on standby earn a discounted dayrate as they do not have crews and have lower costs. Additionally, we recognized $901,000 of revenues during the second quarter of 2009 from the early termination of drilling contracts. Excluding the impact of standby revenues and the

early termination of drilling contracts, average revenue per operating day decreased in the second quarter of 2009 compared to the second quarter of 2008 primarily due to decreases in dayrates for rigs that were operating in the spot market and the expiration of term contracts that were at higher rates. Average direct operating costs per operating day decreased in the second quarter of 2009 compared to the second quarter of 2008 primarily due to decreases in labor and repair costs as well as the impact of rigs earning standby revenues for which no crews were maintained in the second quarter of 2009. 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.

     Our customers have increased their 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 and declining commodity prices, we have experienced a decrease in the number of smaller traditional pressure pumping jobs, which has contributed to the overall decrease in the number of total jobs. Revenues and direct operating costs decreased as a result of a decrease in the number of total jobs. Increased average revenue per job was due to an increase in the proportion of larger jobs to total jobs, which was driven by demand for services associated with unconventional reservoirs partially offset by the impact of reduced pricing. Average direct operating costs per job increased due to the increase in larger jobs and as a result of fixed costs being spread over a significantly reduced number of jobs. In anticipation of increased activity associated with the unconventional reservoirs in the Appalachian Basin, we have added facilities, equipment and personnel in recent years. Delays in the development of these reservoirs and lower commodity prices have caused less demand for our pressure pumping services, negatively impacting the profitability of this business. Selling, general and administrative expenses decreased in the second quarter of 2009 compared to the second quarter of 2008 primarily due to headcount reductions. Significant capital expenditures have been incurred to add capacity and modify and upgrade existing equipment. The increase in depreciation expense is a result of these capital expenditures.

     Revenues and direct operating costs decreased in the second quarter of 2009 compared to the second quarter of 2008 due to decreased sales volume both on land and offshore in the Gulf of Mexico. Selling, general and administrative expenses decreased in the second quarter of 2009 compared to the second quarter of 2008 primarily due to a decrease in compensation costs for sales and support personnel due to headcount reductions.

     Revenues decreased due to lower average sales prices and net daily production of oil and natural gas. Average net daily oil and natural gas production decreased primarily due to production declines on existing wells. Depreciation, depletion and impairment expense in the second quarter of 2009 includes approximately $600,000 incurred to impair certain oil and natural gas properties compared to approximately $79,000 incurred to impair certain oil and natural gas properties in the second quarter of 2008. The increase in impairment charges in 2009 was due to a reduction in commodity price expectations and a decline in production of certain wells. Depletion expense decreased approximately $609,000 primarily due to the impact of decreases in carrying value of properties resulting from impairment charges recognized prior to the second quarter of 2009.

     Selling, general and administrative expenses increased in the second quarter of 2009 compared to the second quarter of 2008 primarily as a result of increased professional fees and increased non-cash stock based compensation. Other operating expenses increased due to an increase in bad debt expense of $1.7 million in the second quarter of 2009 compared to the second quarter of 2008. Gains and losses on the disposal and retirement of assets are treated as part of our corporate activities because such transactions relate to corporate strategy decisions of the Company’s executive management group. In the second quarter of 2008 we recognized a net gain on the disposal of assets of approximately $2.7 million primarily due to the sale of certain assets in our contract drilling segment. Interest expense increased in the second quarter of 2009 compared to the second quarter of 2008 due to amortization of LOC issuance costs and increased fees associated with the unused portion of the LOC.

     The following tables summarize operations by business segment for the six months ended June 30, 2009 and 2008: