Three Months Ended June 30,                             Six Months Ended June 30,
                            2009                       2008                       2009                        2008
Contract
drilling            $ 101,716          63 %    $ 416,835          79 %    $ 327,420          72 %    $   836,984          81 %
Pressure pumping       33,616          21         57,094          11         71,721          16           99,958          10
Drilling and
completion
fluids                 20,267          13         38,745           7         48,097          10           71,295           7
Oil and natural
gas                     5,165           3         13,609           3          9,565           2           22,600           2

                    $ 160,764         100 %    $ 526,283         100 %    $ 456,803         100 %    $ 1,030,837         100 %

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:
• movement of drilling rigs from region to region,

• reactivation of land-based drilling rigs, or

• construction of new drilling rigs.

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.
Critical Accounting Policies
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.
Liquidity and Capital Resources
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:
• to build new drilling rigs,

• to make capital expenditures for the betterment and refurbishment of our drilling rigs,

• to acquire and procure drilling equipment and facilities to support our drilling operations,

• to fund capital expenditures for our pressure pumping and drilling and completion fluids segments, and

• to fund investments in oil and natural gas properties on a working interest basis.

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

                                         Per Share           Total
                                                        (in thousands)
               Paid on March 31, 2009   $      0.05     $         7,655
               Paid on June 30, 2009           0.05               7,675

               Total cash dividends     $      0.10     $        15,330

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. Results of Operations
The following tables summarize operations by business segment for the three months ended June 30, 2009 and 2008:

                                                              2009                2008             %Change
Contract Drilling                                              (Dollars in thousands)
Revenues                                                  $   101,716          $ 416,835            (75.6 )%
Direct operating costs                                    $    56,950          $ 251,381            (77.3 )%
Selling, general and administrative                       $     1,096          $   1,297            (15.5 )%
Depreciation                                              $    58,555          $  57,362              2.1 %
Operating income (loss)                                   $   (14,885 )        $ 106,795              N/M
Operating days                                                  5,720             22,245            (74.3 )%
Average revenue per operating day                         $     17.78          $   18.74             (5.1 )%
Average direct operating costs per operating day          $      9.96          $   11.30            (11.9 )%
Average rigs operating                                             63                244            (74.2 )%
Capital expenditures                                      $   148,447          $  67,815            118.9 %

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.

                                                   2009            2008       %Change
     Pressure Pumping                            (Dollars in thousands)
     Revenues                                  $   33,616       $ 57,094       (41.1 )%
     Direct operating costs                    $   22,862       $ 32,506       (29.7 )%
     Selling, general and administrative       $    4,964       $  5,834       (14.9 )%
     Depreciation                              $    6,688       $  4,477        49.4 %
     Operating income (loss)                   $     (898 )     $ 14,277         N/M
     Total jobs                                     1,681          3,400       (50.6 )%
     Average revenue per job                   $    20.00       $  16.79        19.1 %
     Average direct operating costs per job    $    13.60       $   9.56        42.3 %
     Capital expenditures                      $    6,753       $ 17,689       (61.8 )%

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.

                                                 2009            2008        %Change
      Drilling and Completion Fluids           (Dollars in thousands)
      Revenues                               $   20,267       $ 38,745        (47.7 )%
      Direct operating costs                 $   19,005       $ 31,449        (39.6 )%
      Selling, general and administrative    $    1,757       $  2,517        (30.2 )%
      Depreciation                           $      600       $    724        (17.1 )%
      Operating income (loss)                $   (1,095 )     $  4,055          N/M
      Capital expenditures                   $        -       $  1,525       (100.0 )%

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.

                                                      2009            2008        %Change
 Oil and Natural Gas Production and Exploration      (Dollars in thousands,
                                                      except sales prices)
 Revenues                                          $   5,165        $ 13,609       (62.0 )%
 Direct operating costs                            $   1,820        $  3,529       (48.4 )%
 Depreciation, depletion and impairment            $   2,787        $  2,907        (4.1 )%
 Operating income                                  $     558        $  7,173       (92.2 )%
 Capital expenditures                              $   1,551        $  4,527       (65.7 )%
 Average net daily oil production (Bbls)                 753             814        (7.5 )%
 Average net daily natural gas production (Mcf)        3,478           4,126       (15.7 )%
 Average oil sales price (per Bbl)                 $   57.30        $ 123.71       (53.7 )%
 Average natural gas sales price (per Mcf)         $    3.92        $  11.85       (66.9 )%

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.

                                                             2009               2008             %Change
Corporate and Other                                          (Dollars in thousands)
Selling, general and administrative                       $   8,419          $  8,099                4.0 %
Depreciation                                              $     227          $    203               11.8 %
Other operating expenses                                  $   2,000          $    300              566.7 %
Net loss (gain) on asset disposals/retirements            $     176          $ (2,721 )              N/M
Interest income                                           $     204          $    493              (58.6 )%
Interest expense                                          $     839          $     63            1,231.7 %
Other income                                              $      12          $    353              (96.6 )%

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:

                                                              2009                2008             %Change
Contract Drilling                                              (Dollars in thousands)
Revenues                                                  $   327,420          $ 836,984            (60.9 )%
Direct operating costs                                    $   183,271          $ 495,748            (63.0 )%
Selling, general and administrative                       $     2,082          $   2,821            (26.2 )%
Depreciation                                              $   115,941          $ 113,234              2.4 %
Operating income                                          $    26,126          $ 225,181            (88.4 )%
Operating days                                                 17,193             44,478            (61.3 )%
Average revenue per operating day                         $     19.04          $   18.82              1.2 %
Average direct operating costs per operating day          $     10.66          $   11.15             (4.4 )%
Average rigs operating                                             95                244            (61.1 )%
Capital expenditures                                      $   215,449          $ 135,026             59.6 %

Revenues and direct operating costs decreased in the first six months of 2009 compared to the first six months 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 first six months of 2009 included an average of approximately nine rigs that earned standby revenues of $18.1 million. Rigs on standby earn a discounted dayrate as they do not have crews and have lower costs. Additionally, we recognized $7.5 million of revenues during the first six months of 2009 from the early termination of drilling contracts. Average direct operating costs per operating day decreased in the first six months of 2009 compared to the first six months 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 first six months of 2009. Selling, general and administrative expenses decreased in the first six months of 2009 compared to the first six months of 2008 primarily as a result of lower professional fees and headcount reductions. 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.

                                                   2009            2008       %Change
     Pressure Pumping                            (Dollars in thousands)
     Revenues                                  $   71,721       $ 99,958       (28.2 )%
     Direct operating costs                    $   49,868       $ 61,011       (18.3 )%
     Selling, general and administrative       $   10,799       $ 11,441        (5.6 )%
     Depreciation                              $   12,827       $  8,777        46.1 %
     Operating income (loss)                   $   (1,773 )     $ 18,729         N/M
. . .