UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

Form 10-K/A

Amendment No. 2

(Mark One)

þ		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2007

o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

FOR THE TRANSITION PERIOD FROM            TO

ALLIS-CHALMERS ENERGY INC.

Delaware (State or other jurisdiction of incorporation or organization)		39-0126090 (I.R.S. Employer Identification No.)
5075 WESTHEIMER, SUITE 890 HOUSTON, TEXAS (Address of principal executive offices)		77056 (Zip code)

(713) 369-0550
Registrant’s telephone number, including area code

Title of Security:		Name of Exchange:
Common Stock, par value $0.01 per share		New York Stock Exchange

     Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No þ

     Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d). Yes o No þ

     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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. 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):

Large accelerated filer o		Accelerated filer þ		Non-accelerated filer o		Smaller reporting company o
		(Do not check if a smaller reporting company)

     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

     The aggregate market value of the common equity held by non-affiliates of the registrant, computed using the closing price of the common stock of $22.99 per share on June 30, 2007, as reported on the New York Stock Exchange, was approximately $462,009,706 (affiliates included for this computation only: directors, executive officers and holders of more than 5% of the registrant’s common stock).

     As of June 16, 2008 there were 35,190,284 shares of common stock issued and outstanding.

None

 

 

Explanatory Note

The purpose of this Amendment No. 2 on Form 10-K/A is to respond to comments received from the Securities and Exchange Commission’s Division of Corporation Finance in its letter dated June 20, 2008 regarding our previously filed Annual Report on Form 10-K for the year ended December 31, 2007, filed with the Securities and Exchange Commission, or SEC, on March 7, 2008 (“Original Form 10-K”), and our Amendment No. 1 to the Original Form 10-K, filed with the SEC on April 29, 2008 (“Amendment No. 1”). This amendment amends the following disclosures:

Form 10-K
	•		Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operation,” revised to expand our consolidated and segment results of operations discussion to provide greater insight into the underlying reasons for variances, and guidance on whether or not the results of operations are indicative of expected results beginning on page 3; and
	•		Item 8. “Financial Statements,” revised to remove the label “(unaudited)” from the condensed consolidating statements of cash flow for the year ended December 31, 2006 on page 59 and to correct a label on the consolidated statements of cash flows for the years ended December 31, 2006 and 2005 on page 26;
Form 10-K/A
	•		Item 11. “Executive Compensation,” revised to include the financial and non-financial goals or targets established for fiscal 2007 that were used to determine our named executive officers’ incentive compensation on pages 67-69.

     As required by Rule 12b-15 under the Securities Exchange Act of 1934, as amended, which we refer to as the Exchange Act, new certifications by our Chief Executive Officer and Chief Financial Officer are being filed as exhibits to this Amendment No. 2 on Form 10-K/A under Item 15 of Part IV.

     There are no other changes to the Original Form 10-K or Amendment No. 1 thereto other than those outlined above. This Amendment does not reflect events occurring after the filing of the Original Form 10-K or Amendment No. 1 thereto nor does it modify or update disclosures therein in any way other than as required to reflect the amendment set forth below.

     As used herein, “Allis-Chalmers”, “we”, “our” and “us” may refer to Allis-Chalmers Energy Inc. and its subsidiaries. The use of these terms is not intended to connote any particular corporate status or relationships.

SPECIAL NOTE
REGARDING FORWARD-LOOKING STATEMENTS

      This Amendment No. 2 on Form 10-K/A contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, or the Securities Act, regarding our business, financial condition, results of operations and prospects. Words such as expects, anticipates, intends, plans, believes, seeks, estimates and similar expressions or variations of such words are intended to identify forward-looking statements. However, these are not the exclusive means of identifying forward-looking statements. Although such forward-looking statements reflect our good faith judgment, such statements can only be based on facts and factors currently known to us. Consequently, forward-looking statements are inherently subject to risks and uncertainties, and actual outcomes may differ materially from the results and outcomes discussed in the forward-looking statements. Further information about the risks and uncertainties that may impact us are described in “Risk Factors” beginning on page 14 of our Original Form 10-K. You should read those sections carefully. You should not place undue reliance on forward-looking statements. Forward-looking statements are only as of the date they are made. We undertake no obligation to update publicly any forward-looking statements in order to reflect any event or circumstance occurring after the date they are made or currently unknown facts or conditions or the occurrence of unanticipated events.

TABLE OF CONTENTS

				Page
PART III
Item 7.		Management’s Discussion and Analysis of Financial Condition and Results of Operations		- 2 -
Item 8.		Financial Statements		- 19 -
Item 11.		Executive Compensation		- 63 -
PART IV
Item 15.		Exhibits and Financial Statement Schedules		- 82 -
		Signatures		- 83 -
Consent of UHY LLP
Certification of CEO Pursuant to Section 302
Certification of CFO Pursuant to Section 302
Certification of CEO & CFO Pursuant to Section 1350

PART II

 

 

The following discussion and analysis should be read in conjunction with our selected historical financial data included in our Original Form 10-K and our financial statements and the notes to those financial statements included elsewhere in this document. The following discussion contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 that reflect our plans, estimates and beliefs. Our actual results could differ materially from those anticipated in these forward-looking statements as a result of risks and uncertainties, including, but not limited to, those discussed under “Item 1A. Risk Factors” included in our Original Form 10-K.

 

Overview of Our Business

 

We are a multi-faceted oilfield services company that provides services and equipment to oil and natural gas exploration and production companies throughout the United States, including Texas, Louisiana, New Mexico, Colorado, Oklahoma, Mississippi, Wyoming, Arkansas, West Virginia, offshore in the Gulf of Mexico, and internationally, primarily in Argentina and Mexico. We operate in six sectors of the oil and natural gas service industry: Rental Services; International Drilling; Directional Drilling; Tubular Services; Underbalanced Drilling and Production Services.

 

We derive operating revenues from rates per job that we charge for the labor and equipment required to provide a service and rates per day for equipment and tools that we rent to our customers. The price we charge for our services depends upon several factors, including the level of oil and natural gas drilling activity and the competitive environment in the particular geographic regions in which we operate. Contracts are awarded based on the price, quality of service and equipment, and the general reputation and experience of our personnel. The demand for drilling services has historically been volatile and is affected by the capital expenditures of oil and natural gas exploration and development companies, which can fluctuate based upon the prices of oil and natural gas or the expectation for the prices of oil and natural gas.

 

The number of working drilling rigs, typically referred to as the “rig count,” is an important indicator of activity levels in the oil and natural gas industry. The rig count in the United States increased from 862 as of December 31, 2002 to 1,763 as of February 29, 2008, according to the Baker Hughes rig count. Furthermore, directional and horizontal rig counts increased from 283 as of December 31, 2002 to 817 as of February 29, 2008, which accounted for 33% and 46% of the total U.S. rig count, respectively. The offshore Gulf of Mexico rig count, however, decreased to 58 rigs at February 29, 2008 from 90 rigs one year earlier. We believe this is due to the relocation of rigs to international markets as a result of the high oil prices.

 

Our cost of revenues represents all direct and indirect costs associated with the operation and maintenance of our equipment. The principal elements of these costs are direct and indirect labor and benefits, repairs and maintenance of our equipment, insurance, equipment rentals, fuel and depreciation. Operating expenses do not fluctuate in direct proportion to changes in revenues because, among other factors, we have a fixed base of inventory of equipment and facilities to support our operations, and in periods of low drilling activity we may also seek to preserve labor continuity to market our services and maintain our equipment.

 

Results of Operations

 

In April 2005, we acquired all of the outstanding stock of Delta and, in May 2005, we acquired all of the outstanding stock of Capcoil. We report the operations of Downhole and Capcoil in our Production Services segment and the operations of Safco and Delta in our Rental Services segment. In July 2005, we acquired the 45% interest of M-I in our Underbalanced Drilling subsidiary, AirComp, making us the 100% owner of AirComp. In addition, in July 2005, we acquired the underbalanced drilling assets of W. T. On August 1, 2005, we acquired all of the outstanding capital stock of Target. We included Target results in our Directional Drilling segment because Target’s measurement while drilling equipment is utilized in that segment. On September 1, 2005, we acquired the

casing and tubing service assets of Patterson Services, Inc. We consolidated the results of these acquisitions from the day they were acquired.

 

In January 2006, we acquired all of the outstanding stock of Specialty and in December 2006, we acquired substantially all of the assets of OGR. We report the operations of Specialty and OGR in our Rental Services segment. In April 2006, we acquired all of the outstanding stock of Rogers. We report the operations of Rogers in our Tubular Services segment. In August 2006, we acquired all of the outstanding stock of DLS and in December 2006, we acquired all of the outstanding stock of Tanus. We report the operations of DLS and Tanus in our International Drilling segment. In October 2006, we acquired all of the outstanding stock of Petro Rentals. We report the operations of Petro Rentals in our Production Services segment. We consolidated the results of these acquisitions from the day they were acquired.

 

In June 2007, we acquired all of the outstanding stock of Coker and in July 2007, we acquired all of the outstanding stock of Diggar and in November 2007, we acquired substantially all of the assets of Diamondback. We report the operations of Coker, Diggar and Diamondback in our Directional Drilling segment. In October 2007, we acquired all of the outstanding stock of Rebel. We report the operations of Rebel in our Tubular Services segment. We consolidated the results of these acquisitions from the day they were acquired.

 

The foregoing acquisitions affect the comparability from period to period of our historical results, and our historical results may not be indicative of our future results.

 

Comparison of Years Ended December 31, 2007 and December 31, 2006

 

Our revenues for the year ended December 31, 2007 were $571.0 million, an increase of 83.6% compared to $311.0 million for the year ended December 31, 2006. Revenues increased in all of our business segments due principally to the acquisitions completed during the two year period ended December 31, 2007, the investment in new equipment and the opening of new operating locations. The most significant increase in revenues was due to the acquisition of DLS on August 14, 2006 which established our International Drilling segment. The International Drilling segment generated $215.8 million in revenues for the twelve months ended December 31, 2007 compared to $69.5 million for the period from the date of the DLS acquisition to December 31, 2006. Revenues also increased significantly at our Rental Services segment due to the acquisition of the OGR assets on December 18, 2006. The OGR assets, including its two rental yards, expanded our assets available for rent. The OGR assets generated revenues of $82.2 million for the twelve months ended December 31, 2007 compared to $2.1 million for the period from the date of acquisition of the OGR assets to December 31, 2006. We experienced a decline in demand for our Rental Services in the last half of 2007 due to the hurricane season and a reduction of drilling activity in the U.S. Gulf of Mexico as rigs departed the U.S Gulf in favor of the international markets. Our Directional Drilling segment revenues increased in the 2007 period compared to the 2006 period due to acquisitions completed in the third and fourth quarters of 2007 which added downhole motors, measurement-while-drilling, or MWD, tools, and directional drilling personnel resulting in increased capacity and increased market penetration. Revenues increased at our Underbalanced Drilling segment due to the purchase of additional equipment, principally new compressor packages, and expansion of operations into new geographic regions. Revenues increased in our Production Services segment principally due to the $20.6 million in revenues from the Petro-Rental acquisition completed October 16, 2006 and additional coil tubing equipment acquired in 2007, which was offset by a decrease in our revenue from capillary assets of $6.7 million which were sold on June 29, 2007. Except for our Rental Services segment, we believe these gains in revenues are sustainable dependent on a favorable oil and natural gas price environment, a stable rig count and the level of capital expenditures of our customers. Future growth and increased revenues in our Rental Services segment is contingent upon achieving success in marketing our rental assets to the U.S. land drilling and international markets, and improvement in the offshore U.S. Gulf of Mexico activity.

 

Our gross margin for the year ended December 31, 2007 increased 69.9% to $178.6 million, or 31.3% of revenues, compared to $105.1 million, or 33.8%, of revenues for the year ended December 31, 2006. The increase in gross profit is due to the increase in revenues in all of our business segments. The decrease in gross profit as a percentage of revenues is primarily due to the 151.3% increase in depreciation expense to $50.9 million in 2007 from $20.3 million in 2006. The primary increase in depreciation expense is due to the acquisitions of the OGR assets, DLS and Petro-Rental and our capital expenditures. The increase in our depreciation expense related to the OGR assets was $15.9 million to $16.6 million for the year ended December 31, 2007 compared to $650,000 for the

period from the date of the acquisition of the OGR assets to December 31, 2006. Depreciation expense from DLS increased $7.2 million to $11.3 million for the year ended December 31, 2007 from $4.1 million for the period from the date of the acquisition of DLS to December 31, 2006. Depreciation expense from Petro-Rental for the year ended December 31, 2007 was $3.6 million compared to $688,000 for the period from the date of acquisition of Petro-Rental to December 31, 2006. Our cost of revenues consists principally of our labor costs and benefits, equipment rentals, maintenance and repairs of our equipment, depreciation, insurance and fuel. Because many of our costs are fixed, our gross profit as a percentage of revenues is generally affected by our level of revenues. The sustainability and growth in our gross margin is principally dependent upon the sustainability and growth in our revenues. However, factors affecting the performance of our Rental Services segment in 2007 as discussed previously have a negative impact on our gross margin percentage as our Rental Services segment operates at a higher gross margin than our other segments. Therefore, the level of revenues and gross margin from our Rental Services segment has a significant impact on our overall gross margin and gross margin percentage. We expect our depreciation expense to increase as we continue to purchase capital equipment to strengthen and enhance our existing operations.

 

General and administrative expense was $58.6 million for the year ended December 31, 2007 compared to $35.5 million for the year ended December 31, 2006. General and administrative expense increased due to the acquisitions, and the hiring of additional sales, operations, accounting and administrative personnel. As a percentage of revenues, general and administrative expenses were 10.3% in 2007 compared to 11.4% in 2006. General and administrative expense includes share-based compensation expense of $4.7 million in 2007 and $3.0 million in 2006. Without any significant acquisitions, we expect the growth of our general and administrative expense to decrease in the near future as our share-based compensation expense for future years is currently expected to decrease.

 

On June 29, 2007, we sold our capillary tubing assets that were part of our Production Services segment. The total consideration was approximately $16.3 million in cash. We recognized a gain of $8.9 million related to the sale of these assets.

 

Amortization expense was $4.1 million for the year ended December 31, 2007 compared to $1.9 million for the year ended December 31, 2006. The increase in amortization expense is primarily due to the amortization of intangible assets in connection with our acquisition of the OGR assets, which increased $2.2 million to $2.3 million for the year ended December 31, 2007 compared to $96,000 for the period from the date of the acquisition of the OGR assets to December 31, 2006. Without any significant acquisitions, we expect a slight increase in amortization expense as future years will include a full year of amortization of intangible assets related to acquisitions completed in 2007.

 

Income from operations for the year ended December 31, 2007 totaled $124.8 million, an 84.2% increase over the $67.7 million in income from operations for the year ended December 31, 2006, reflecting the increase in our revenues of $260.0 million and the resulting increase in our gross profit of $73.5 million, offset in part by increased general and administrative expense of $23.1 million and increased amortization expense of $2.2 million. Our income from operations as a percentage of revenues increased slightly to 21.9% in 2007 from 21.8% in 2006. Income from operations in the 2007 period includes an $8.9 million gain from the sale of our capillary tubing assets in the second quarter of 2007.

 

Our net interest expense was $46.3 million for the year ended December 31, 2007, compared to $20.3 million for the year ended December 31, 2006. Interest expense increased in 2007 due to our increased debt. In August 2006 we issued $95.0 million of senior notes bearing interest at 9.0% to fund a portion of the acquisition of DLS. In January 2007 we issued $250.0 million of senior notes bearing interest at 8.5% to pay off, in part, the $300.0 million bridge loan utilized to complete the OGR acquisition and for working capital. This bridge loan was repaid on January 29, 2007. The average interest rate on the bridge loan was approximately 10.6%. Interest expense for 2007 includes the write-off of deferred financing fees of $1.2 million related to the repayment of the bridge loan. Interest expense includes amortization expense of deferred financing costs of $1.9 million and $1.5 million for 2007 and 2006, respectively. Our net interest expense is dependent upon our level of debt and cash on hand, which are principally dependent upon acquisitions we complete, our capital expenditures and our cash flows from operations.

 

Our provision for income taxes for the year ended December 31, 2007 was $28.8 million, or 36.4% of our net income before income taxes, compared to $11.4 million, or 24.3% of our net income before income taxes for 2006. The increase in our provision for income taxes is attributable to the increase in our operating income and a higher

effective tax rate. The effective tax rate in 2006 was favorably impacted by the reversal of our valuation allowance on our deferred tax assets. The valuation allowance was reversed due to operating results that allowed for the realization of our deferred tax assets.

 

We had net income attributed to common stockholders of $50.4 million for the year ended December 31, 2007, an increase of 41.6%, compared to net income attributed to common stockholders of $35.6 million for the year ended December 31, 2006.

 

The following table compares revenues and income from operations for each of our business segments for the years ended December 31, 2007 and December 31, 2006. Income from operations consists of our revenues less cost of revenues, general and administrative expenses, and depreciation and amortization:

 

 

Rental Services.  Our Rental Services revenues were $121.2 million for the year ended December 31, 2007, an increase of 135.2% from the $51.5 million in revenues for the year ended December 31, 2006. Income from operations increased 86.9% to $49.1 million in 2007 compared to $26.3 million in 2006. The increase in revenue and operating income is primarily attributable to the acquisition of the OGR assets in December 2006. The OGR assets, including its two rental yards, expanded our assets available for rent. We generated $82.2 million for the twelve months ended December 31, 2007 compared to $2.1 million for the period from the date of acquisition of the OGR assets to December 31, 2006. Income from operations as a percentage of revenues decreased to 40.5% for 2007 compared to 51.0% for the prior year as a result of higher depreciation expense associated with the OGR acquisition and capital expenditures. Our depreciation expense for the OGR assets increased $15.9 million to $16.6 million for the year ended December 31, 2007 compared to $650,000 for the period from the date of acquisition of the OGR assets to December 31, 2006. Rental Services revenues and operating income was impacted by a more competitive market environment due to the decreased U.S. Gulf of Mexico drilling activity in the last half of 2007 attributed to the hurricane season and the departure of drilling rigs in favor of the international markets. Future growth and increased revenues in our Rental Services segment is contingent upon achieving success in marketing our rental assets to the U.S. land drilling and international markets, and improvement in the offshore U.S. Gulf of Mexico activity.

 

International Drilling.  On August 14, 2006, we acquired DLS which established our International Drilling segment. Our International Drilling revenues were $215.8 million for the year ended December 31, 2007, an increase from the $69.5 million in revenues for the period from the date of the DLS acquisition until December 31, 2006. Income from operations increased to $38.8 million in 2007 compared to $12.2 million from the date of the DLS acquisition until December 31, 2006. Income from operations as percentage of revenue increased to 18.0% for 2007 compared to 17.6% for 2006. We believe the increase in the percentage was primarily due to price increases implemented in 2007. During 2007 we placed orders for 16 service rigs (workover rigs and pulling rigs) and four drilling rigs. Four of the service rigs were delivered in the fourth quarter of 2007. We expect all the rigs to be placed in service during the first three quarters of 2008. We believe these levels in revenues and operating income are sustainable assuming a stable rig count and a favorable oil and natural gas price environment in Argentina, labor-related disruptions affecting the oil and natural gas industry in Argentina and resulting cost increases can affect our revenues and operating margins until we are able to increase rig rates to offset such costs. We expect to benefit from the activation of the new rigs as they are delivered throughout 2008.

Directional Drilling.  Revenues for the year ended December 31, 2007 for our Directional Drilling segment were $96.1 million, an increase of 25.6% from the $76.5 million in revenues for the year ended December 31, 2006. The increase in revenues is due to the purchase of additional MWD tools and the benefit of acquisitions completed in the last half of 2007 which added downhole motors, MWDs, and directional drillers. The additional equipment and personnel enabled us to strengthen our presence in new geographic markets and increase our market penetration. The impact of the additional MWD tools and the acquisitions of Diggar and Coker completed in the last half of 2007 are not easily identifiable as they were quickly integrated with our pre-existing operations. The acquisition of Diamondback provided $3.1 million of revenues from the date of acquisition to December 31, 2007. Income from operations increased 6.7% to $18.8 million for 2007 from $17.7 million for 2006. Income from operations as a percentage of revenues decreased to 19.6% for 2007 compared to 23.1% for the prior year. The decrease in our operating margin as a percentage of revenues is due to increased expenses for downhole motor rentals and repairs, experienced primarily in the first three quarters of 2007 prior to the recent additions to our downhole motor fleet, increased personnel costs and increased depreciation expense. We believe the gain in revenue is sustainable assuming a stable rig count, continued strength in the demand for directional and horizontal drilling services and a favorable oil and natural gas price environment in the U.S. We expect our operating results to benefit from the downhole motors acquired in the Diggar acquisition, the acquisitions of Coker and Diamondback and the purchase of additional MWDs and downhole motors in 2007. With more downhole motors we are able to reduce our reliance on third-party rental motors and the related costs.

 

Tubular Services.  Revenues for the year ended December 31, 2007 for the Tubular Services segment were $53.5 million, an increase of 5.2% from the $50.9 million in revenues for the year ended December 31, 2006. Revenues from domestic operations increased to $45.6 million in 2007 from $44.4 million in 2006 as a result of the investment in new equipment. Revenues from Mexican operations increased to $7.9 million in 2007 from $6.5 million in 2006. Income from operations decreased 14.3% to $10.7 million in 2007 from $12.5 million in 2006. Income from operations as a percentage of revenues decreased to 20.1% for 2007 compared to 24.7% for the prior year. The results of our Tubular Services segment were impacted by an increasingly competitive environment domestically for casing and tubing services, exacerbated by the decline in drilling activity in the U.S. Gulf of Mexico in the last half of 2007, and decreased sales of power tongs in 2007 compared to 2006. While revenues from Mexican operations increased 21.5% in 2007 compared to 2006, they were impacted in the fourth quarter of 2007, by severe weather and flooding in Mexico. We believe these gains in revenues are sustainable assuming a stable rig count, a favorable oil and natural gas price environment and the absence of significant weather disruptions in the U.S. and in Mexico. We expect the competitive challenges in the domestic tubular services market to continue and limit improvement in our operating income margins.

 

Underbalanced Drilling.  Our Underbalanced Drilling revenues were $51.0 million for the year ended December 31, 2007, an increase of 18.4% compared to $43.0 million in revenues for the year ended December 31, 2006. Income from operations increased 21.1% to $13.1 million in 2007 compared to income from operations of $10.8 million in 2006. Income from operations as a percentage of revenues increased slightly to 25.7% in 2007 from 25.1% in 2006. Our Underbalanced Drilling revenues and operating income for the 2007 period increased compared to the 2006 period due in part to our investment in additional equipment, principally new compressors and new “foam” units. During 2007 Underbalanced Drilling was affected by a decrease in drilling activity in certain geographic areas by some of our customers, offset by an increased market presence and growth in drilling activity in other, more attractive geographic areas. We believe these gains in revenue are sustainable assuming a stable rig count and a favorable oil and natural gas price environment in the U.S. Future growth will be dependent on our ability to penetrate the new developing land drilling markets and our future investment in capital equipment.

 

Production Services Segment.  Our Production Services revenues were $33.4 million for the year ended December 31, 2007, compared to $19.6 million in revenues for the year ended December 31, 2006. Income from operations was $10.5 million in 2007 compared to income from operations of $2.1 million in 2006. Revenues for 2007 increased compared to 2006 due primarily to our acquisition of Petro Rentals on October 17, 2006, the addition of two coil tubing units in the fourth quarter of 2006, one unit in the first quarter of 2007 and one additional unit delivered at the end of the second quarter of 2007, offset in part by a reduction in revenue generated from our capillary tubing assets, which were sold in 2007. Our capillary tubing revenue decreased $6.7 million to $5.6 million for the period from January 1, 2007 until the date of sale, June 29, 2007, compared to $12.3 million for the year ended December 31, 2006. The increase in income from operations can be attributed to an $8.9 million gain on sale of our capillary tubing assets. During 2007 our Production Services segment experienced delays in the delivery and activation of new coil tubing units. As a result, we experienced low utilization for our coil tubing units and increases

in personnel expenses, including increased lodging, relocation and training expenses for the crews without the benefit of corresponding increases in revenues. We expect 2008 revenues to be stable as the revenue reduction related to the sale of the capillary assets is expected to be offset by the new coil tubing units placed in service in 2007 and 2008, assuming a stable rig count and a favorable oil and natural gas environment in the U.S. Our income from operations is expected to decline as we will not have the gain from the sale of the capillary assets that we realized in 2007.

 

Comparison of Years Ended December 31, 2006 and December 31, 2005

 

Our revenues for the year ended December 31, 2006 was $311.0 million, an increase of 187.9% compared to $108.0 million for the year ended December 31, 2005. Revenues increased in all of our business segments due to the successful integration of acquisitions completed in the third quarter of 2005 and during 2006, the investment in new equipment, improved pricing for our services, the addition of operations and sales personnel and the opening of new operations offices. Revenues increased most significantly due to the acquisition of DLS on August 14, 2006 which expanded our operations to a sixth operating segment, International Drilling. Revenues also increased significantly at our Rental Services segment due to the acquisition of Specialty effective January 1, 2006. Our Tubular Services segment also had a substantial increase in revenue, primarily due to the acquisitions of the casing and tubing assets of Patterson Services, Inc. on September 1, 2005, and the acquisition of Rogers as of April 1, 2006, along with the investment in additional equipment, improved market conditions and increased market penetration for our services in South Texas, East Texas, Louisiana and the U.S. Gulf of Mexico. Revenues increased at our Underbalanced Drilling segment due to the purchase of additional equipment and improved pricing for our services. Our Directional Drilling segment revenues increased in the 2006 period compared to the 2005 period due to improved pricing for directional drilling services, the August 2005 acquisition of Target which provides MWD tools and the purchase of additional down-hole motors and MWDs which increased our capacity and market presence. The impact of the acquisitions of DLS, Rogers and Target, including the additional MWDs, was to increase consolidated revenues by $69.5 million, $10.8 million and $7.6 million, respectively. The impact of the acquisitions of Specialty and the casing and tubing assets of Patterson Services, Inc. are not easily identifiable as they were quickly integrated with our pre-existing operations, but our Rental Services revenues improved to $51.5 million for the year ended December 31, 2006 compared to $5.1 million for the year ended December 31, 2005 and our Tubular Services revenues increased to $50.9 million compared to $20.9 million for the same period.

 

Our gross margin for the year ended December 31, 2006 increased 243.8% to $105.1 million, or 33.8% of revenues, compared to $30.6 million, or 28.3%, of revenues for the year ended December 31, 2005. The increase in gross profit is due to the increase in revenues in all of our business segments. The increase in gross profit as a percentage of revenues is primarily due to the acquisition of Specialty as of January 1, 2006, in the high margin rental tool business, the improved pricing for our services generally and the investments in new capital equipment. Also contributing to our improved gross margin was the acquisition of Target, the purchase of additional MWD’s and the acquisition of Rogers. The increase in gross profit was partially offset by an increase in depreciation expense of 315.7% to $20.3 million compared to $4.9 million for 2005. The increase is due to additional depreciable assets resulting from acquisitions and capital expenditures. The acquisitions of DLS, Petro-Rental, Rogers and Target, including additional MWDs increased depreciation expense by $4.1 million, $688,000, $530,000 and $439,000, respectively. While we cannot specifically identify the impact that the Specialty acquisition had on our gross margin due to the reason described in the preceding paragraph, the gross margin on our total Rental Services segment increased $28.9 million to $32.1 million for the year ended December 31, 2006 from $3.2 million for the year ended December 31, 2005 after the impact of an increase in depreciation expense of $6.7 million to $7.1 million for 2006 from $385,000 for 2005. The gross margin provided from the acquisitions of Rogers and Target, including additional MWDs was $4.7 million and $3.3 million, respectively. Our cost of revenues consists principally of our labor costs and benefits, equipment rentals, maintenance and repairs of our equipment, depreciation, insurance and fuel. Because many of our costs are fixed, our gross profit as a percentage of revenues is generally affected by our level of revenues.

 

General and administrative expense was $35.5 million for the year ended December 31, 2006 compared to $15.6 million for the year ended December 31, 2005. General and administrative expense increased due to additional expenses associated with the acquisitions, and the hiring of additional sales, operations and

administrative personnel. General and administrative expense also increased because of increased accounting and consulting fees and other expenses in connection with initiatives to strengthen our internal control processes, costs related to Sarbanes Oxley compliance efforts and increased corporate accounting and administrative staff. As a percentage of revenues, general and administrative expenses were 11.4% in 2006 compared to 14.4% in 2005.

 

We adopted SFAS No. 123R, Share-Based Payment, effective January 1, 2006. This statement requires all share-based payments to employees, including grants of employee stock options, to be recognized in the financial statements based on their grant-date fair values. We adopted SFAS No. 123R using the modified prospective transition method, utilizing the Black-Scholes option pricing model for the calculation of the fair value of our employee stock options. Under the modified prospective method, we record compensation cost related to unvested stock awards as of December 31, 2005 by recognizing the unamortized grant date fair value of these awards over the remaining vesting periods of those awards with no change in historical reported earnings. Therefore, we recorded an expense of $3.4 million related to stock awards for the year ended December 31, 2006 of which $3.0 million was recorded in general and administrative expense with the balance being recorded as a direct cost. Prior to January 1, 2006, we accounted for our stock-based compensation using Accounting Principle Board Opinion No. 25, or APB No. 25. Under APB No. 25, compensation expense is recognized for stock options with an exercise price that is less than the market price on the grant date of the option. Accordingly, no compensation cost was recognized under APB No. 25.

 

Amortization expense was $1.9 million for the year ended December 31, 2006 compared to $1.5 million for the year ended December 31, 2005. The increase in amortization expense is due to the amortization of intangible assets in connection with our acquisitions. The 2006 acquisitions of Rogers, the OGR assets, Petro and DLS resulted in amortization expense of $166,000, $96,000, $63,000 and $11,000, respectively.

 

Income from operations for the year ended December 31, 2006 totaled $67.7 million, a 401.0% increase over the $13.5 million in income from operations for the year ended December 31, 2005, reflecting the increase in our revenues of $202.9 million and the resulting increase in our gross profit of $74.5 million, offset in part by increased general and administrative expenses of $20.0 million. Our income from operations as a percentage of revenues increased to 21.8% in 2006 from 12.5% in 2005 due to the increase in our gross margin which offset the increases in amortization expense and general and administrative expenses.

 

Our net interest expense was $20.3 million for the year ended December 31, 2006, compared to $4.7 million for the year ended December 31, 2005. Interest expense increased in 2006 due to our increased debt. In January of 2006 we issued $160.0 million of senior notes bearing interest at 9.0% to fund the acquisition of Specialty, pay off other outstanding debt and for working capital. In August 2006 we issued an additional $95.0 million of senior notes bearing interest at 9.0% to fund a portion of the acquisition of DLS. On December 18, 2006, we borrowed $300.0 million in a senior unsecured bridge loan to fund the acquisition of OGR. The average interest rate on the bridge loan was approximately 10.6%. Interest expense for 2006 includes the write-off of $453,000 related to financing fees on the bridge loan. This bridge loan was repaid on January 29, 2007 and the remaining $1.2 million of financing fees were written off in 2007. In the third quarter of 2005, we incurred debt retirement expense of $1.1 million related to the refinancing of our debt. This amount includes prepayment penalties and the write-off of deferred financing fees from a previous financing.

 

Minority interest in income of subsidiaries for the year ended December 31, 2006 was $0 compared to $488,000 for the corresponding period in 2005 due to the our acquisition of the minority interest at AirComp on July 11, 2005.

 

Our provision for income taxes for the year ended December 31, 2006 was $11.4 million, or 24.3% of our net income before income taxes, compared to $1.3 million, or 15.8% of our net income before income taxes for 2005. The increase in our provision for income taxes is attributable to the significant increase in our operating income which resulted in the utilization of our deferred tax assets including our net operating losses, and the increase in percentage of income taxes to net income before income taxes attributable to our operations in Argentina which are taxed at 35.0%.

 

We had net income attributed to common stockholders of $35.6 million for the year ended December 31, 2006, an increase of 396.5%, compared to net income attributed to common stockholders of $7.2 million for the year ended December 31, 2005.

The following table compares revenues and income from operations for each of our business segments for the years ended December 31, 2006 and December 31, 2005. Income from operations consists of our revenues less cost of revenues, general and administrative expenses, and depreciation and amortization:

 

 

Rental Services Segment.  Our rental services revenues were $51.5 million for the year ended December 31, 2006, an increase from the $5.1 million in revenues for the year ended December 31, 2005. Income from operations increased to $26.3 million in 2006 compared to $1.3 million in 2005. The increase in revenue and operating income is primarily attributable to the acquisition of Specialty effective January 1, 2006, improved pricing, improved utilization of our inventory of rental equipment and to a lesser extent, the acquisition of the OGR assets in December 2006. The impact of the Specialty acquisition is not easily identifiable as the acquisition was quickly integrated with our pre-existing operations. The acquisition of the OGR assets provided $2.1 million in revenues in 2006.

 

International Drilling Segment.  Our international drilling revenues were $69.5 million for the year ended December 31, 2006, and our income from operations was $12.2 million. This segment of our operations was created with the acquisition of DLS in August of 2006.

 

Directional Drilling Segment.  Revenues for the year ended December 31, 2006 for our Directional Drilling segment were $76.5 million, an increase of 64.2% from the $46.6 million in revenues for the year ended December 31, 2005. Income from operations increased 139.1% to $17.7 million for 2006 from $7.4 million for 2005. The improved results for this segment are due to the increase in drilling activity in the Texas and Gulf Coast areas, improved pricing, the acquisition of Target as of August 1, 2005 and the purchase of an additional six MWDs. The acquisition of Target and the additional MWDs provided an additional $7.6 million of revenue and $2.8 million of operating income. Our increased operating expenses as a result of the addition of operations and personnel were more than offset by the growth in revenues and improved pricing for our services.

 

Tubular Services Segment.  Revenues for the year ended December 31, 2006 for the Tubular Services segment were $50.9 million, an increase of 143.1% from the $20.9 million in revenues for the year ended December 31, 2005. Revenues from domestic operations increased to $44.4 million in 2006 from $14.5 million in 2005 as a result of the acquisition of Rogers, the acquisition of the casing and tubing assets of Patterson Services, Inc. on September 1, 2005 and investment in new equipment, all of which resulted in increased market penetration for our services in South Texas, East Texas, Louisiana and the U.S. Gulf of Mexico. The year ended December 2005 was also adversely impacted by hurricane activity in September of 2005. The impact of the acquisition of casing and tubing assets of Patterson Services, Inc, are not easily identifiable as they were quickly integrated into with our pre-existing operations, but the Rogers acquisition generated an additional $10.8 million in revenues in 2006. Revenues from Mexican operations increased to $6.5 million in 2006 from $6.4 million in 2005. Income from operations increased 151.2% to $12.5 million in 2006 from $5.0 million in 2005. The increase in this segment’s operating income is due to increased revenues both domestically and in our Mexico operations.

 

Underbalanced Drilling Segment.  Our underbalanced drilling revenues were $43.0 million for the year ended December 31, 2006, an increase of 67.7% compared to $25.7 million in revenues for the year ended December 31, 2005. Income from operations increased 92.6% to $10.8 million in 2006 compared to income from operations of $5.6 million in 2005. Our underbalanced drilling revenues and operating income for the 2006 period

increased compared to the 2005 period due in part to the acquisition of the air drilling assets of W. T., our investment in additional equipment and improved pricing in West Texas. The impact of the acquisition of the air drilling assets of W.T. is not easily identifiable as they were quickly integrated into our pre-existing operations.

 

Production Services Segment.  Our production services revenues were $19.6 million for the year ended December 31, 2006, compared to $9.8 million in revenues for the year ended December 31, 2005. Income from operations was $2.1 million in 2006 compared to a loss from operations of $99,000 in 2005. The increase in revenues is attributable to the acquisition of Petro-Rentals completed in October 2006, the acquisition of Capcoil on May 1, 2005 and improved utilization and pricing for our services. The increase in operating income is primarily related to the operations of Petro-Rental and the addition of two coil tubing units in the fourth quarter of 2006, which provided $5.5 million of revenue in 2006.

 

Liquidity and Capital Resources

 

Our on-going capital requirements arise primarily from our need to service our debt, to acquire and maintain equipment, to fund our working capital requirements and to complete acquisitions. Our primary sources of liquidity are proceeds from the issuance of debt and equity securities and cash flows from operations. We had cash and cash equivalents of $43.7 million at December 31, 2007 compared to $39.7 million at December 31, 2006.

 

Operating Activities

 

In the year ended December 31, 2007, we generated $103.5 million in cash from operating activities. Net income for the year ended December 31, 2007 was $50.4 million. Non-cash additions to net income totaled $60.6 million in the 2007 period consisting primarily of $55.0 million of depreciation and amortization, $4.9 million related to the expensing of stock options as required under SFAS No. 123R, $8.0 million of deferred income tax, $730,000 for a provision for bad debts and $3.2 million of amortization and write-off of deferred financing fees, partially offset by $2.3 million of gain from the disposition of equipment and a $8.9 million gain from the sale of capillary assets.

 

During the year ended December 31, 2007, changes in working capital used $7.6 million in cash, principally due to an increase of $30.8 million in accounts receivable, an increase of $4.5 million in other assets and an increase in inventories of $5.4 million, offset by a decrease of $8.2 million in other current assets, an increase of $10.7 million in accounts payable, an increase of $6.0 million in accrued interest, an increase of $4.0 million in accrued employee benefits and payroll taxes, an increase of $1.5 million in accrued expenses and an increase in other long-term liabilities of $2.7 million. Our accounts receivables increased at December 31, 2007 primarily due to the increase in our revenues in 2007. Other assets increase primarily due to the contract costs related to the deployment of new rigs for our International Drilling segment. The decrease in other current assets is principally due to the collection of the working capital adjustment from the OGR acquisition for approximately $7.1 million in the first quarter of 2007. Accrued interest increased at December 31, 2007 due principally to interest accrued on our 8.5% senior notes issued in January 2007 and our 9.0% senior notes issued in August 2006 which are both payable semi-annually. Our accounts payable, accrued employee benefits and payroll taxes and other accrued expenses increased primarily due to the increase in costs due to our growth in revenues and acquisition completed in 2007. Other long-term liabilities increased primarily due to the deferral of contract revenue related to our new rigs being constructed in the International drilling segment.

 

In the year ended December 31, 2006, we generated $53.7 million in cash from operating activities. Net income for the year ended December 31, 2006 was $35.6 million. Non-cash additions to net income totaled $27.6 million in the 2006 period consisting primarily of $22.1 million of depreciation and amortization, $3.4 million related to the expensing of stock options as required under SFAS No. 123R, $2.2 million of deferred income tax, $781,000 for a provision for bad debts and $1.5 million for amortization of finance fees, including the bridge loan fees, partially offset by $2.4 million of gain from the disposition of equipment.

 

During the year ended December 31, 2006, changes in working capital used $9.9 million in cash, principally due to an increase of $23.2 million in accounts receivable, an increase of $2.6 million in inventories, a decrease of $2.3 million in accounts payable, offset in part by a decrease in other current assets of $2.5 million, an increase of $11.4 million in accrued interest, an increase of $3.4 million in accrued employee benefits and payroll taxes and an

increase of $872,000 in accrued expenses. Our accounts receivables increased at December 31, 2006 primarily due to the increase in our revenues in 2006. Accrued interest increased at December 31, 2006 due principally to interest accrued on our 9.0% senior notes, which are payable semi-annually. Our accrued employee benefits and payroll taxes and other accrued expenses increased primarily due to the increase in costs due to our growth in revenues and acquisition completed in 2006.

 

In the year ended December 31, 2005, we generated $3.6 million in cash from operating activities. Net income for the year ended December 31, 2005 was $7.2 million. Non-cash additions to net income totaled $7.4 million in the 2005 period consisting primarily of $6.4 million of depreciation and amortization, $488,000 of minority interest in the income of a subsidiary, $962,000 in amortization and write-off of financing fees in conjunction with a refinancing and $219,000 for a provision for bad debts, partially offset by $669,000 of gain from the disposition of equipment.

 

During the year ended December 31, 2005, changes in working capital used $11.0 million in cash, principally due to an increase of $10.7 million in accounts receivable, an increase of $3.1 million in inventories, an increase in other assets of $936,000, a decrease in other liabilities of $266,000 and a decrease of $97,000 in accrued expenses, offset in part by a decrease in other current assets of $929,000, an increase of $2.4 million in accounts payable, an increase of $324,000 in accrued interest and a increase of $443,000 in accrued employee benefits and payroll taxes. Our accounts receivables increased at December 31, 2005 due primarily to the increase in our revenues in 2005. Accounts payable increased by $2.4 million at December 31, 2005 due to the increase in our cost of sales associated with the increase in our revenues and the acquisitions completed in 2005 and 2004.

 

Investing Activities

 

During the year ended December 31, 2007, we used $137.1 million in investing activities consisting of four acquisitions and our capital expenditures. During the year ended December 31, 2007, we completed the following acquisitions for a total net cash outlay of $41.0 million, consisting of the purchase price and acquisition costs less cash acquired:

 

 

In addition we made capital expenditures of approximately $113.2 million during the year ended December 31, 2007, including $34.9 million to increase our inventory of equipment and replace “lost-in-hole” equipment in the Rental Services segment, $28.9 million to purchase, improve and replace equipment in our International Drilling segment, $11.2 million to purchase equipment for our Directional Drilling segment, $17.4 million to purchase and improve equipment in our Underbalanced Drilling segment, $9.3 million to purchase and improve our Tubular Services equipment and approximately $10.7 million to expand our Production Services segment. We received proceeds of $16.3 million from the sale of our capillary assets. We also received $12.8 million from the sale of assets during the year ended December 31, 2007, comprised mostly from equipment “lost-in-hole” from our Rental Services segment ($11.0 million) and our Directional Drilling segment ($1.4 million). We also made advance payments of $11.5 million on the purchase of new drilling and service rigs to be delivered in 2008 for our International Drilling segment.

 

During the year ended December 31, 2006, we used $559.4 million in investing activities consisting of six acquisitions and our capital expenditures. During the year ended December 31, 2006, we completed the following

acquisitions for a total net cash outlay of $526.6 million, consisting of the purchase price and acquisition costs less cash acquired:

 

 

In addition we made capital expenditures of approximately $39.7 million during the year ended December 31, 2006, including $4.5 million to replace “lost-in-hole” equipment and to increase our inventory of equipment in the Rental Services segment, $5.8 million to purchase, improve and replace equipment in our international drilling segment, $5.1 million to purchase equipment for our Directional Drilling segment, $7.7 million to purchase and improve equipment in our Underbalanced Drilling segment, $11.0 million to purchase and improve our tubular services equipment and approximately $5.3 million to expand our Production Services segment. We also received $6.9 million from the sale of assets during the year ended December 31, 2006, comprised mostly from equipment “lost-in-hole” from our Rental Services segment ($3.8 million) and our Directional Drilling segment ($1.8 million).

 

During the year ended December 31, 2005, we used $53.1 million in investing activities. During the year ended December 31, 2005, we completed the following acquisitions for a total net cash outlay of $36.9 million, consisting of the purchase price and acquisition costs less cash acquired:

 

 

In addition we made capital expenditures of approximately $17.8 million during the year ended December 31, 2005, including $2.9 million to purchase equipment for our Directional Drilling segment, $7.0 million to purchase and improve equipment in our Underbalanced Drilling segment, $5.2 million to purchase and improve our tubular services equipment and approximately $1.5 million to expand our Production Services segment. We also received $1.6 million from the sale of assets during the year ended December 31, 2005, comprised mostly from equipment lost in the hole from our Directional Drilling segment ($1.0 million) and our Rental Services segment ($408,000).

Financing Activities

 

During the year ended December 31, 2007, financing activities provided a net of $37.6 million in cash. We received $250.0 million in borrowings from the issuance of our 8.5% senior notes due 2017. We also received $100.1 million in net proceeds from the issuance of 6,000,000 shares of our common stock, $1.7 million on the tax benefit of stock compensation plans and $3.3 million from the proceeds of warrant and option exercises for 882,624 shares of our common stock. The proceeds were used to repay long-term debt totaling $309.7 million and to pay $7.8 million in debt issuance costs. The repayment of long-term debt consisted primarily of the repayment of our $300.0 million bridge loan which was used to fund the acquisition of the OGR assets.

 

During the year ended December 31, 2006, financing activities provided a net of $543.6 million in cash. We received $557.8 million in borrowings under long-term debt facilities, consisting primarily of the issuance of $255.0 million of our 9.0% senior notes due 2014 and a $300.0 million senior unsecured bridge loan. The bridge loan, which was repaid on January 29, 2007, was used to fund the acquisition of the OGR assets. We also received $46.3 million in net proceeds from the issuance of 3,450,000 shares of our common stock, $6.4 million on the tax benefit of options and $6.3 million from the proceeds of warrant and option exercises for 1,851,377 shares of our common stock. The proceeds were used to repay long-term debt totaling $54.0 million, repay $6.4 million in net borrowings under our revolving lines of credit, repay related party debt of $3.0 million and to pay $9.9 million in debt issuance costs.

 

During the year ended December 31, 2005, financing activities provided a net of $44.1 million in cash. We received $56.3 million in borrowings under long-term debt facilities, $15.5 million in net proceeds from the issuance of 1,761,034 shares of our common stock, $2.5 million in net borrowings under our revolving lines of credit and $1.4 million from the proceeds of warrant and option exercises for 1,076,154 shares of our common stock. The proceeds were used to repay long-term debt totaling $28.2 million, repay related party debt of $1.5 million and to pay $1.8 million in debt issuance costs.

 

On January 18, 2006 and August 14, 2006, we closed on private offerings, to qualified institutional buyers pursuant to Rule 144A under the Securities Act, of $160.0 million and $95.0 million aggregate principal amount of our senior notes, respectively. The senior notes are due January 15, 2014 and bear interest at 9.0%. The proceeds were used to fund the acquisitions of Specialty and DLS, to repay existing debt and for general corporate purposes. Debt repaid included all outstanding balances under our credit agreement, including a $42.1 million term loan and $6.4 million in working capital advances, a $4.0 million subordinated note issued in connection with acquisition of AirComp, approximately $3.0 million subordinated note issued in connection with the acquisition of Tubular, approximately $548,000 on a real estate loan and approximately $350,000 on outstanding equipment financing.

 

On December 18, 2006, we closed on a $300.0 million senior unsecured bridge loan. The bridge loan was due 18 months after closing and had a weighted average interest rate of 10.6%. The bridge loan, which was repaid on January 29, 2007, was used to fund the acquisition of OGR.

 

In January 2007, we closed on a private offering, to qualified institutional buyers pursuant to Rule 144A under the Securities Act, of $250.0 million principal amount of 8.5% senior notes due 2017. The proceeds of the senior notes offering, together with a portion of the proceeds of our concurrent common stock offering, were used to repay the debt outstanding under our $300.0 million bridge loan facility which we incurred to finance our acquisition of substantially all the assets of OGR.

 

On January 18, 2006, we also executed an amended and restated credit agreement which provides for a $25.0 million revolving line of credit with a maturity of January 2010. This agreement contains customary events of default and financial covenants and limits our ability to incur additional indebtedness, make capital expenditures, pay dividends or make other distributions, create liens and sell assets. Our obligations under the agreement are secured by substantially all of our assets excluding the DLS assets, but including 2/3 of our shares of DLS. On April 26, 2007, we entered into a Second Amended and Restated Credit Agreement, which increased our revolving line of credit to $62.0 million, and has a final maturity date of April 26, 2012. On December 3, 2007, we entered into a First Amendment to Second Amended and Restated Credit Agreement, which increased our revolving line of credit to $90.0 million. The amended and restated credit agreement contains customary events of default and financial covenants and limits our ability to incur additional indebtedness, make capital expenditures, pay dividends

or make other distributions, create liens and sell assets. Our obligations under the amended and restated credit agreement are secured by substantially all of our assets located in the United States. At December 31, 2007 and 2006, no amounts were borrowed on the facility but availability is reduced by outstanding letters of credit of $8.4 million and $9.7 million, respectively.

 

As part of our acquisition of DLS, we assumed various bank loans with floating interest rates based on LIBOR plus a margin and terms ranging from 2 to 5 years. The weighted average interest rates on these loans was 6.7% and 7.0% at December 31, 2007 and 2006, respectively. The bank loans are denominated in U.S. dollars and the outstanding amount due as of December 31, 2007 and 2006 was $4.9 million and $7.3 million, respectively.

 

As part of the acquisition of MCA in 2001, we issued a note to the sellers of MCA in the original amount of $2.2 million accruing interest at a rate of 5.75% per annum. The note was reduced to $1.5 million as a result of the settlement of a legal action against the sellers in 2003. In March 2005, we reached an agreement with the sellers and holders of the note as a result of an action brought against us by the sellers. Under the terms of the agreement, we paid the holders of the note $1.0 million in cash, and agreed to pay an additional $350,000 on June 1, 2006, and an additional $150,000 on June 1, 2007, in settlement of all claims. At December 31, 2007 and 2006 the outstanding amounts due were $0 and $150,000, respectively.

 

In connection with the purchase of Delta, we issued to the sellers a note in the amount of $350,000. The note bore interest at 2% and the principal and accrued interest was repaid on its maturity of April 1, 2006. In connection with the acquisition of Rogers, we issued to the seller a note in the amount of $750,000. The note bears interest at 5.0% and is due April 3, 2009. In connection with the purchase of Coker, we issued to the seller a note in the amount of $350,000. The note bears interest at 8.25% and is due June 29, 2008. In connection with the purchase of Diggar, we issued to the seller a note in the amount of $750,000. The note bears interest at 6.0% and is due July 26, 2008. In connection with the purchase of Rebel, we issued to the sellers notes in the amount of $500,000. The notes bear interest at 5.0% and are due October 23, 2008.

 

In connection with the purchase of Tubular, we agreed to pay a total of $1.2 million to the seller in exchange for a non-compete agreement. Monthly payments of $20,576 were due under this agreement through January 31, 2007. In connection with the purchase of Safco-Oil Field Products, Inc., or Safco, we also agreed to pay a total of $150,000 to the sellers in exchange for a non-compete agreement. We were required to make annual payments of $50,000 through September 30, 2007. In connection with the purchase of Capcoil, we agreed to pay a total of $500,000 to two management employees in exchange for non-compete agreements. We are required to make annual payments of $110,000 through May 2008. Total amounts due under these non-compete agreements at December 31, 2007 and 2006 were $110,000 and $270,000, respectively.

 

In 2000 we compensated directors, including current directors Nederlander and Toboroff, who served on the board of directors from 1989 to March 31, 1999 without compensation, by issuing promissory notes totaling $325,000. The notes bear interest at the rate of 5.0%. At December 31, 2007 and 2006, the principal and accrued interest on these notes totaled approximately $32,000.

 

We have various rig and equipment financing loans with interest rates ranging from 7.8% to 8.7% and terms of 2 to 5 years. As of December 31, 2007 and 2006, the outstanding balances for rig and equipment financing loans were $595,000 and $3.5 million, respectively. In January 2006, we prepaid $350,000 of the outstanding equipment loans with proceeds from our senior notes offering.

 

In April 2006 and August 2006, we obtained insurance premium financings in the amount of $1.9 million and $896,000 with fixed interest rates of 5.6% and 6.0%, respectively. Under terms of the agreements, amounts outstanding are paid over 10 month and 11 month repayment schedules. The outstanding balance of these notes was approximately $1.0 million as of December 31, 2006. In April 2007 and August 2007, we obtained insurance premium financings in the amount of $3.2 million and $1.3 with fixed interest rates of 5.9% and 5.7%, respectively. Under terms of the agreements, amounts outstanding are paid over 11 month repayment schedules. The outstanding balance of these notes was approximately $1.7 million as of December 31, 2007.

 

We also have various capital leases with terms that expire in 2008. As of December 31, 2007 and 2006, amounts outstanding under capital leases were $14,000 and $414,000, respectively.

The following table summarizes our obligations and commitments to make future payments under our notes payable, operating leases, employment contracts and consulting agreements for the periods specified as of December 31, 2007.

 

 

We have identified capital expenditure projects that will require up to approximately $140.0 million in 2008, exclusive of any acquisitions, of which $82.7 million is committed as of December 31, 2007. We believe that our cash generated from operations, cash on hand and cash available under our credit facilities will provide sufficient funds for our identified projects.

 

We intend to implement a growth strategy of increasing the scope of services through both internal growth and acquisitions. We are regularly involved in discussions with a number of potential acquisition candidates. We expect to make capital expenditures to acquire and to maintain our existing equipment. Our performance and cash flow from operations will be determined by the demand for our services which in turn are affected by our customers’ expenditures for oil and natural gas exploration and development and industry perceptions and expectations of future oil and natural gas prices in the areas where we operate. We will need to refinance our existing debt facilities as they become due and provide funds for capital expenditures and acquisitions. To effect our expansion plans, we will require additional equity or debt financing in excess of our current working capital and amounts available under credit facilities. There can be no assurance that we will be successful in raising the additional debt or equity capital or that we can do so on terms that will be acceptable to us.

 

Recent Developments

 

On January 23, 2008, we entered into an Agreement and Plan of Merger with Bronco Drilling Company, Inc., or Bronco, whereby Bronco will become a wholly-owned subsidiary of Allis-Chalmers. The merger agreement, which was approved by our Board of Directors and the Board of Directors of Bronco, provides that the Bronco stockholders will receive aggregate merger consideration with a value of approximately $437.8 million, consisting of (a) $280.0 million in cash and (b) shares of our common stock, par value $0.01 per share, having an aggregate value of approximately $157.8 million. The number of shares of our common stock to be issued will be based on the average closing price of our common stock for the ten-trading day period ending two days prior to the closing. Completion of the merger is conditioned upon, among other things, adoption of the merger agreement by Bronco’s stockholders and approval by our stockholders of the issuance of shares of our common stock to be used as merger consideration.

 

In order to finance some or all of the cash component of the merger consideration, the repayment of outstanding Bronco debt and transaction expenses, we expect to incur debt of up to $350.0 million. We intend to obtain up to $350.0 million from either (1) a permanent debt financing of up to $350.0 million or (2) if the permanent debt financing cannot be consummated prior to the closing date of the merger, the draw down under a senior unsecured bridge loan facility in an aggregate principal amount of up to $350.0 million to be arranged by RBC Capital Markets Corporation and Goldman Sachs Credit Partners L.P., acting as joint lead arrangers and joint bookrunners. We executed a commitment letter, dated January 28, 2008, with Royal Bank of Canada and Goldman Sachs who have each, subject to certain conditions, severally committed to provide 50% of the loans under the senior unsecured bridge facility to us. This commitment for the bridge loan facility will terminate on July 31, 2008,

if we have not drawn the bridge facility by such date and the merger is not consummated by such date. The commitment may also terminate prior to July 31, 2008, if the merger is abandoned or a material condition to the merger is not satisfied or we breach our obligations under the commitment letter. We may use the proceeds of the bridge facility to finance the cash component of the merger consideration, repay outstanding Bronco debt and pay transaction expenses.

 

On January 29, 2008, Burt A. Adams resigned as our President and Chief Operating Officer, effective February 28, 2008. Mr. Adams will remain as a member of our Board of Directors. On January 29, 2008, Mark C. Patterson was elected our Senior Vice-President — Rental Services. On January 29, 2008, Terrence P. Keane was elected our Senior Vice-President — Oilfield Services.

 

On January 31, 2008, we entered into an agreement with BCH Ltd., or BCH, to invest $40.0 million in cash in BCH in the form of a 15% Convertible Subordinated Secured debenture. The debenture is convertible, at any time, at our option into 49% of the common equity of BCH. At the end of two years, we have the option to acquire the remaining 51% of BCH from its parent, BrazAlta Resources Corp., or BrazAlta, based on an independent valuation from a mutually acceptable investment bank. BCH is a Canadian-based oilfield services company engaged in contract drilling operations exclusively in Brazil.

 

On February 15, 2008, through our DLS subsidiary in Argentina, we entered into a $25.0 million import finance facility with a bank. Borrowings under this facility will be used to fund a portion of the purchase price of the new drilling and service rigs ordered for our international drilling operation. The facility is available for borrowings until December 31, 2008. Each drawdown shall be repaid over four years in equal semi-annual instalments beginning one year after each disbursement with the final principal payment due not later than March 15, 2013. Interest is payable every six months. The import finance facility is unsecured and contains customary events of default and financial covenants and limits DLS’ ability to incur additional indebtedness, make capital expenditures, create liens and sell assets.

 

Critical Accounting Policies

 

We have identified the policies below as critical to our business operations and the understanding of our results of operations. The impact and any associated risks related to these policies on our business operations is discussed throughout Management’s Discussion and Analysis of Financial Condition and Results of Operations where such policies affect our reported and expected financial results. For a detailed discussion on the application of these and other accounting policies, see Note 1 in the Notes to the Consolidated Financial Statements included elsewhere in this document. Our preparation of this report requires us to make estimates and assumptions that affect the reported amount of assets and liabilities, disclosure of contingent assets and liabilities at the date of our financial statements, and the reported amounts of revenue and expenses during the reporting period. There can be no assurance that actual results will not differ from those estimates.

 

Allowance For Doubtful Accounts.  The determination of the collectibility of amounts due from our customers requires us to use estimates and make judgments regarding future events and trends, including monitoring our customer payment history and current credit worthiness to determine that collectibility is reasonably assured, as well as consideration of the overall business climate in which our customers operate. Those uncertainties require us to make frequent judgments and estimates regarding our customers’ ability to pay amounts due us in order to determine the appropriate amount of valuation allowances required for doubtful accounts. Provisions for doubtful accounts are recorded when it becomes evident that the customers will not be able to make the required payments at either contractual due dates or in the future.

 

Revenue Recognition.  We provide rental equipment and drilling services to our customers at per day, or daywork, and per job contractual rates and recognize the drilling related revenue as the work progresses and when collectibility is reasonably assured. Revenue from daywork contracts is recognized when it is realized or realizable and earned. On daywork contracts, revenue is recognized based on the number of days completed at fixed rates stipulated by the contract. For certain contracts, we receive lump-sum and other fees for equipment and other mobilization costs. Mobilization fees and the related costs are deferred and amortized over the contract terms when material. The Securities and Exchange Commission’s Staff Accounting Bulletin No. 104, Revenue Recognition in Financial Statements, provides guidance on the SEC staff’s views on application of generally accepted accounting

principles to selected revenue recognition issues. Our revenue recognition policy is in accordance with generally accepted accounting principles and SAB No. 104.

 

Impairment Of Long-Lived Assets.  Long-lived assets, which include property, plant and equipment, goodwill and other intangibles, comprise a significant amount of our total assets. We make judgments and estimates in conjunction with the carrying value of these assets, including amounts to be capitalized, depreciation and amortization methods and useful lives. Additionally, the carrying values of these assets are reviewed for impairment or whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable. An impairment loss is recorded in the period in which it is determined that the carrying amount is not recoverable. This requires us to make long-term forecasts of our future revenues and costs related to the assets subject to review. These forecasts require assumptions about demand for our products and services, future market conditions and technological developments. Significant and unanticipated changes to these assumptions could require a provision for impairment in a future period.

 

Goodwill And Other Intangibles.  As of December 31, 2007, we have recorded approximately $138.4 million of goodwill and $35.2 million of other identifiable intangible assets. We perform purchase price allocations to intangible assets when we make a business combination. Business combinations and purchase price allocations have been consummated for acquisitions in all of our reportable segments. The excess of the purchase price after allocation of fair values to tangible assets is allocated to identifiable intangibles and thereafter to goodwill. Subsequently, we perform our initial impairment tests and annual impairment tests in accordance with Financial Accounting Standards Board No. 141, Business Combinations, and Financial Accounting Standards Board No. 142, Goodwill and Other Intangible Assets. These initial valuations used two approaches to determine the carrying amount of the individual reporting units. The first approach is the Discounted Cash Flow Method, which focuses on our expected cash flow. In applying this approach, the cash flow available for distribution is projected for a finite period of years. Cash flow available for distribution is defined as the amount of cash that could be distributed as a dividend without impairing our future profitability or operations. The cash flow available for distribution and the terminal value (our value at the end of the estimation period) are then discounted to present value to derive an indication of value of the business enterprise. This valuation method is dependent upon the assumptions made regarding future cash flow and cash requirements. The second approach is the Guideline Company Method which focuses on comparing us to selected reasonably similar publicly traded companies. Under this method, valuation multiples are: (i) derived from operating data of selected similar companies; (ii) evaluated and adjusted based on our strengths and weaknesses relative to the selected guideline companies; and (iii) applied to our operating data to arrive at an indication of value. This valuation method is dependent upon the assumption that our value can be evaluated by analysis of our earnings and our strengths and weaknesses relative to the selected similar companies. Significant and unanticipated changes to these assumptions could require a provision for impairment in a future period.

 

Income Taxes.  The determination and evaluation of our annual income tax provision involves the interpretation of tax laws in various jurisdictions in which we operate and requires significant judgment and the use of estimates and assumptions regarding significant future events such as the amount, timing and character of income, deductions and tax credits. Changes in tax laws, regulations and our level of operations or profitability in each jurisdiction may impact our tax liability in any given year. While our annual tax provision is based on the information available to us at the time, a number of years may elapse before the ultimate tax liabilities in certain tax jurisdictions are determined. Current income tax expense reflects an estimate of our income tax liability for the current year, withholding taxes, changes in tax rates and changes in prior year tax estimates as returns are filed. Deferred tax assets and liabilities are recognized for the anticipated future tax effects of temporary differences between the financial statement basis and the tax basis of our assets and liabilities using the enacted tax rates in effect at year end. A valuation allowance for deferred tax assets is recorded when it is more-likely-than-not that the benefit from the deferred tax asset will not be realized. We provide for uncertain tax positions pursuant to FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes — an Interpretation of FASB Statement No. 109.

 

It is our intention to permanently reinvest all of the undistributed earnings of our non-U.S. subsidiaries in such subsidiaries. Accordingly, we have not provided for U.S. deferred taxes on the undistributed earnings of our non-U.S. subsidiaries. If a distribution is made to us from the undistributed earnings of these subsidiaries, we could be required to record additional taxes. Because we cannot predict when, if at all, we will make a distribution of these undistributed earnings, we are unable to make a determination of the amount of unrecognized deferred tax liability.

Recently Issued Accounting Standards

 

In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements. SFAS No. 157 clarifies the principle that fair value should be based on the assumptions that market participants would use when pricing an asset or liability and establishes a fair value hierarchy that prioritizes the information used to develop those assumptions. Under the standard, fair value measurements would be separately disclosed by level within the fair value hierarchy. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years, with early adoption permitted. Subsequently, the FASB provided for a one-year deferral of the provisions of Statement No. 157 for non-financial assets and liabilities that are recognized or disclosed at fair value in the consolidated financial statements on a non-recurring basis. We believe that the adoption of SFAS No. 157 will not have a material impact on our financial position, results of operations or cash flows.

 

In December 2007, the FASB issued SFAS No. 141(R), Business Combinations. This statement retains the fundamental requirements in SFAS No. 141, “Business Combinations” that the acquisition method of accounting be used for all business combinations and expands the same method of accounting to all transactions and other events in which one entity obtains control over one or more other businesses or assets at the acquisition date and in subsequent periods. This statement replaces SFAS No. 141 by requiring measurement at the acquisition date of the fair value of assets acquired, liabilities assumed and any non-controlling interest. Additionally, SFAS No. 141(R) requires that acquisition-related costs, including restructuring costs, be recognized as expense separately from the acquisition. SFAS No. 141(R) applies prospectively to business combinations for fiscal years beginning after December 15, 2008. We will adopt SFAS No. 141(R) beginning January 1, 2009 and apply to future acquisitions.

 

In February 2007, the FASB issued Statement No. 159, The Fair Value Option for Financial Assets and Financial Liabilities, which permits entities to elect to measure many financial instruments and certain other items at fair value. Upon adoption of SFAS No. 159, an entity may elect the fair value option for eligible items that exist at the adoption date. Subsequent to the initial adoption, the election of the fair value option should only be made at the initial recognition of the asset or liability or upon a re-measurement event that gives rise to the new-basis of accounting. All subsequent changes in fair value for that instrument are reported in earnings. SFAS No. 159 does not affect any existing accounting literature that requires certain assets and liabilities to be recorded at fair value nor does it eliminate disclosure requirements included in other accounting standards. SFAS No. 159 is effective as of the beginning of each reporting entity’s first fiscal year that begins after November 15, 2007. We are currently evaluating the provisions of SFAS No. 159 and have not yet determined the impact, if any, on our financial statements.

 

In December 2007, the FASB issued SFAS No. 160, Non-controlling Interests in Consolidated Financial Statements — an amendment of ARB No. 51. SFAS No. 160 requires (i) that non-controlling (minority) interests be reported as a component of shareholders’ equity, (ii) that net income attributable to the parent and to the non-controlling interest be separately identified in the consolidated statement of operations, (iii) that changes in a parent’s ownership interest while the parent retains its controlling interest be accounted for as equity transactions, (iv) that any retained non-controlling equity investment upon the deconsolidation of a subsidiary be initially measured at fair value, and (v) that sufficient disclosures are provided that clearly identify and distinguish between the interests of the parent and the interests of the non-controlling owners. SFAS No. 160 is effective for annual periods beginning after December 15, 2008 and should be applied prospectively. The presentation and disclosure requirements of the statement shall be applied retrospectively for all periods presented. We believe the adoption of SFAS No. 160 will not have a material impact on our financial position or results of operations.

 

Off-Balance Sheet Arrangements

 

We have no off balance sheet arrangements, other than normal operating leases and employee contracts, that have or are likely to have a current or future material effect on our financial condition, changes in financial condition, revenues, expenses, results of operations, liquidity, capital expenditures or capital resources. We have a $90.0 million revolving line of credit with a maturity of January 2010. At December 31, 2007, no amounts were borrowed on the facility but availability is reduced by outstanding letters of credit of $8.4 million. We do not guarantee obligations of any unconsolidated entities.

 

INDEX TO FINANCIAL STATEMENTS

 

ALLIS-CHALMERS ENERGY INC. AND SUBSIDIARIES

 

 

Management’s Report on Internal Control Over Financial Reporting

 

As management, we are responsible for establishing and maintaining adequate internal control over financial reporting for Allis-Chalmers Energy Inc. and its subsidiaries, or Allis-Chalmers. In order to evaluate the effectiveness of internal control over financial reporting, as required by Section 404 of the Sarbanes-Oxley Act of 2002, we have conducted an assessment, including testing, using the criteria in Internal Control-Integral Framework issued by the Committee of Sponsoring Organization of the Treadway Commission (COSO). Allis-Chalmers’ system of internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America. Because of its inherent limitation, internal control over financial reporting may not prevent or detect misstatements.

 

Based on our assessment, we have concluded that Allis-Chalmers maintained effective internal control over financial reporting as of December 31, 2007, based on criteria in Internal Control-Integrated Framework issued by the COSO. The effectiveness of Allis-Chalmers internal control over financial reporting as of December 31, 2007 has been audited by UHY LLP, an independent registered public accounting firm, as stated in their report, which is included herein.

 

Management’s Certifications

 

The certifications of Allis-Chalmers’ Chief Executive Officer and Chief Financial Officer required by the Sarbanes-Oxley Act of 2002 have been included as Exhibits 31 and 32 in Allis-Chalmers’ Form 10-K.

 

ALLIS-CHALMERS ENERGY INC.

 

 

To the Board of Directors and Stockholders

Allis-Chalmers Energy Inc.

Houston, Texas

 

We have audited the accompanying consolidated balance sheets of Allis-Chalmers Energy Inc. and subsidiaries (the “Company”) as of December 31, 2007 and 2006, and the related consolidated statements of operations, stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2007. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements and financial statement schedule based on our audits.

 

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

 

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Allis-Chalmers Energy Inc. and subsidiaries as of December 31, 2007 and 2006, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2007, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

 

As discussed in Note 6 to the consolidated financial statements, effective January 1, 2007, the Company adopted FASB Interpretations No. 48: Accounting for Uncertainty in Income Taxes an Interpretation of FASB Statement No. 109 and, as discussed in Note 1, effective January 1, 2006, the Company adopted Statement of Financial Accounting Standards No. 123 (Revised 2004): Share Based Payment.

 

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Allis-Chalmers Energy Inc.’s internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 6, 2008 expressed an unqualified opinion thereon.

 

/s/ UHY LLP

 

Houston, Texas

March 6, 2008

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

 

The Board of Directors and

Stockholders of Allis-Chalmers Energy Inc.:

 

We have audited Allis-Chalmers Energy Inc.’s internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Allis-Chalmers Energy Inc.’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

 

We conducted our audit in accordance with the standards of the Public Company Accounting of Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

 

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

 

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

 

In our opinion, Allis-Chalmers Energy Inc. and subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on the COSO criteria.

 

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Allis-Chalmers Energy Inc. and subsidiaries as of December 31, 2007 and 2006, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2007, and our report dated March 6, 2008 expressed an unqualified opinion thereon.

 

/s/ UHY LLP

 

Houston, Texas

March 6, 2008

 

 

The accompanying Notes are an integral part of the Consolidated Financial Statements.

 

 

The accompanying Notes are an integral part of the Consolidated Financial Statements.

 

 

The accompanying Notes are an integral part of the Consolidated Financial Statements.

 

 

The accompanying Notes are an integral part of the Consolidated Financial Statements.

 

 

Organization of Business

 

Allis-Chalmers Energy Inc. (“Allis-Chalmers”, “we”, “our” or “us”) was incorporated in Delaware in 1913. We provide services and equipment to oil and natural gas exploration and production companies throughout the United States including Texas, Louisiana, New Mexico, Colorado, Oklahoma, Mississippi, Wyoming, Arkansas, West Virginia, offshore in the Gulf of Mexico, and internationally, primarily in Argentina and Mexico. We operate in six sectors of the oil and natural gas service industry: Rental Services; International Drilling; Directional Drilling; Tubular Services; Underbalanced Drilling and Production Services.

 

The nature of our operations and the many regions in which we operate subject us to changing economic, regulatory and political conditions. We are vulnerable to near-term and long-term changes in the demand for and prices of oil and natural gas and the related demand for oilfield service operations.

 

Use of Estimates

 

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Future events and their effects cannot be perceived with certainty. Accordingly, our accounting estimates require the exercise of judgment. While management believes that the estimates and assumptions used in the preparation of the consolidated financial statements are appropriate, actual results could differ from those estimates. Estimates are used for, but are not limited to, determining the following: allowance for doubtful accounts, recoverability of long-lived assets and intangibles, useful lives used in depreciation and amortization, income taxes and valuation allowances. The accounting estimates used in the preparation of the consolidated financial statements may change as new events occur, as more experience is acquired, as additional information is obtained and as our operating environment changes.

 

Principles of Consolidation

 

The consolidated financial statements include the accounts of Allis-Chalmers and its subsidiaries. Our subsidiaries at December 31, 2007 are AirComp LLC (“AirComp”), Allis-Chalmers Tubular Services LLC (“Tubular”), Strata Directional Technology LLC (“Strata”), Allis-Chalmers Rental Services LLC (“Rental”), Allis-Chalmers Production Services LLC (“Production”), Allis-Chalmers Management LLC, Allis-Chalmers Holdings Inc., DLS Drilling, Logistics & Services Corporation (“DLS”), DLS Argentina Limited, Tanus Argentina S.A. (“Tanus”), Petro-Rentals LLC (“Petro-Rental”) and Rebel Rentals LLC (“Rebel”). All significant inter-company transactions have been eliminated.

 

Revenue Recognition

 

We provide rental equipment and drilling services to our customers at per day, or daywork, and per job contractual rates and recognize the drilling related revenue as the work progresses and when collectibility is reasonably assured. Revenue from daywork contracts is recognized when it is realized or realizable and earned. On daywork contracts, revenue is recognized based on the number of days completed at fixed rates stipulated by the contract. For certain contracts, we receive lump-sum and other fees for equipment and other mobilization costs. Mobilization fees and the related costs are deferred and amortized over the contract terms when material. We recognize reimbursements received for out-of-pocket expenses incurred as revenues and account for out-of-pocket expenses as direct costs. Payments from customers for the cost of oilfield rental equipment that is damaged or lost-in-hole are reflected as revenues. We recognized revenue from damaged or lost-in-hole equipment of $12.6 million, $2.4 million and $970,000 for the years ended December 31, 2007, 2006 and 2005, respectively. The Securities and Exchange Commission’s (SEC) Staff Accounting Bulletin (SAB) No. 104, Revenue Recognition

 

ALLIS-CHALMERS ENERGY INC.

 

Notes to Consolidated Financial Statements — (Continued)

 

In Financial Statements (“SAB No. 104”), provides guidance on the SEC staff’s views on the application of generally accepted accounting principles to selected revenue recognition issues. Our revenue recognition policy is in accordance with generally accepted accounting principles and SAB No. 104.

 

Allowance for Doubtful Accounts

 

Accounts receivable are customer obligations due under normal trade terms. We sell our services to oil and natural gas exploration and production companies. We perform continuing credit evaluations of its customers’ financial condition and although we generally do not require collateral, letters of credit may be required from customers in certain circumstances.

 

The allowance for doubtful accounts represents our estimate of the amount of probable credit losses existing in our accounts receivable. Significant individual accounts receivable balances which have been outstanding greater than 90 days are reviewed individually for collectibility. We have a limited number of customers with individually large amounts due at any given date. Any unanticipated change in any one of these customer’s credit worthiness or other matters affecting the collectibility of amounts due from such customers could have a material effect on the results of operations in the period in which such changes or events occur. After all attempts to collect a receivable have failed, the receivable is written off against the allowance. As of December 31, 2007 and 2006, we had recorded an allowance for doubtful accounts of $1.9 million and $826,000 respectively. Bad debt expense was $1.3 million, $781,000 and $219,000 for the years ended December 31, 2007, 2006 and 2005, respectively.

 

Cash Equivalents

 

We consider all highly liquid investments with an original maturity of three months or less at the time of purchase to be cash equivalents.

 

Inventories

 

Inventories are stated at the lower of cost or market. Cost is determined using the first — in, first — out (“FIFO”) method or the average cost method, which approximates FIFO, and includes the cost of materials, labor and manufacturing overhead.

 

Property and Equipment

 

Property and equipment is recorded at cost less accumulated depreciation. Certain equipment held under capital leases are classified as equipment and the related obligations are recorded as liabilities.

 

Maintenance and repairs, which do not improve or extend the life of the related assets, are charged to operations when incurred. Refurbishments and renewals are capitalized when the value of the equipment is enhanced for an extended period. When property and equipment are sold or otherwise disposed of, the asset account and related accumulated depreciation account are relieved, and any gain or loss is included in operations.

 

The cost of property and equipment currently in service is depreciated over the estimated useful lives of the related assets, which range from three to twenty years. Depreciation is computed on the straight-line method for financial reporting purposes. Capital leases are amortized using the straight-line method over the estimated useful lives of the assets and lease amortization is included in depreciation expense. Depreciation expense charged to operations was $50.9 million, $20.3 million and $4.9 million for the years ended December 31, 2007, 2006 and 2005, respectively.

 

Goodwill, Intangible Assets and Amortization

 

Goodwill, including goodwill associated with equity method investments, and other intangible assets with infinite lives are not amortized, but tested for impairment annually or more frequently if circumstances indicate that

 

ALLIS-CHALMERS ENERGY INC.

 

Notes to Consolidated Financial Statements — (Continued)

 

impairment may exist. Intangible assets with finite useful lives are amortized either on a straight-line basis over the asset’s estimated useful life or on a basis that reflects the pattern in which the economic benefits of the intangible assets are realized.

 

The impairment test requires the allocation of goodwill and all other assets and liabilities to reporting units. If the fair value of the reporting unit is less than the book value (including goodwill) then goodwill is reduced to its implied fair value and the amount of the write-down is charged against earnings. We perform impairment tests on the carrying value of our goodwill on an annual basis as of December 31st for each of our reportable segments. As of December 31, 2007 and 2006, no impairment was deemed necessary. Increases in estimated future costs or decreases in projected revenues could lead to an impairment of all or a portion of our goodwill in future period.

 

Impairment of Long-Lived Assets

 

Long-lived assets, which include property, plant and equipment, and other intangible assets, and certain other assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. An impairment loss is recorded in the period in which it is determined that the carrying amount is not recoverable. The determination of recoverability is made based upon the estimated undiscounted future net cash flows, excluding interest expense. The impairment loss is determined by comparing the fair value, as determined by a discounted cash flow analysis, with the carrying value of the related assets.

 

Financial Instruments

 

Financial instruments consist of cash and cash equivalents, accounts receivable and payable, and debt. The carrying value of cash and cash equivalents and accounts receivable and payable approximate fair value due to their short-term nature. We believe the fair values and the carrying value of our debt would not be materially different due to the instruments’ interest rates approximating market rates for similar borrowings at December 31, 2007 and 2006.

 

Concentration of Credit and Customer Risk

 

Financial instruments that potentially subject us to concentrations of credit risk consist principally of cash and cash equivalents and trade accounts receivable. As of December 31, 2007, we have approximately $2.5 million of cash and cash equivalents residing in Argentina. We transact our business with several financial institutions. However, the amount on deposit in six financial institutions exceeded the $100,000 federally insured limit at December 31, 2007 by a total of $13.2 million. Management believes that the financial institutions are financially sound and the risk of loss is minimal.

 

We sell our services to major and independent domestic and international oil and natural gas companies. We perform ongoing credit valuations of our customers and provide allowances for probable credit losses where appropriate. In 2007 and 2006, one of our customers, Pan American Energy LLC Sucursal Argentina, or Pan American Energy, represented 20.7% and 11.7% of our consolidated revenues, respectively. In 2005 none of our customers accounted for more than 10% of our consolidated revenues. Revenues from Materiales y Equipo Petroleo, or Matyep, represented 3.4%, 8.3% and 94.5% of our international revenues in 2007, 2006 and 2005, respectively. Revenues from Pan American Energy represented 51.0% and 45.6% of our international revenues in 2007 and 2006, respectively.

 

Debt Issuance Costs

 

The costs related to the issuance of debt are capitalized and amortized to interest expense using the straight-line method, which approximates the interest method, over the maturity periods of the related debt.

 

ALLIS-CHALMERS ENERGY INC.

 

Notes to Consolidated Financial Statements — (Continued)

 

Income Taxes

 

Our income tax expense is based on our income, statutory tax rates and tax planning opportunities available to us in the various jurisdictions in which we operate. We provide for income taxes based on the tax laws and rates in effect in the countries in which operations are conducted and income is earned. Our income tax expense is expected to fluctuate from year to year as our operations are conducted in different taxing jurisdictions and the amount of pre-tax income fluctuates.

 

The determination and evaluation of our annual income tax provision involves the interpretation of tax laws in various jurisdictions in which we operate and requires significant judgment and the use of estimates and assumptions regarding significant future events such as the amount, timing and character of income, deductions and tax credits. Changes in tax laws, regulations and our level of operations or profitability in each jurisdiction may impact our tax liability in any given year. While our annual tax provision is based on the information available to us at the time, a number of years may elapse before the ultimate tax liabilities in certain tax jurisdictions are determined.

 

Current income tax expense reflects an estimate of our income tax liability for the current year, withholding taxes, changes in tax rates and changes in prior year tax estimates as returns are filed. Deferred tax assets and liabilities are recognized for the anticipated future tax effects of temporary differences between the financial statement basis and the tax basis of our assets and liabilities using the enacted tax rates in effect at year end. A valuation allowance for deferred tax assets is recorded when it is more-likely-than-not that the benefit from the deferred tax asset will not be realized. We provide for uncertain tax positions pursuant to FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes — an Interpretation of FASB Statement No. 109 (“FIN 48”). Our policy is that we recognize interest and penalties accrued on any unrecognized tax benefits as a component of income tax expense. As of the date of adoption of FIN 48, we did not have any accrued interest or penalties associated with any unrecognized tax benefits. For United States federal tax purposes, our tax returns for the tax years 2001 through 2006 remain open for examination by the tax authorities. Our foreign tax returns remain open for examination for the tax years 2001 through 2006. Generally, for state tax purposes, our 2002 through 2006 tax years remain open for examination by the tax authorities under a four year statute of limitations, however, certain states may keep their statute open for six to ten years.

 

It is our intention to permanently reinvest all of the undistributed earnings of our non-U.S. subsidiaries in such subsidiaries. Accordingly, we have not provided for U.S. deferred taxes on the undistributed earnings of our non-U.S. subsidiaries. If a distribution is made to us from the undistributed earnings of these subsidiaries, we could be required to record additional taxes. Because we cannot predict when, if at all, we will make a distribution of these undistributed earnings, we are unable to make a determination of the amount of unrecognized deferred tax liability.

 

Stock-Based Compensation

 

We adopted SFAS No. 123R, Share-Based Payment (“SFAS No. 123R”), effective January 1, 2006. This statement requires all share-based payments to employees, including grants of employee stock options, to be recognized in the financial statements based on their grant-date fair values. Compensation cost for awards granted prior to, but not vested, as of January 1, 2006 would be based on the grant date attributes originally used to value those awards for pro forma purposes under SFAS No. 123, Accounting for Stock-Based Compensation (“SFAS No. 123”). We adopted SFAS No. 123R using the modified prospective transition method, utilizing the Black-Scholes option pricing model for the calculation of the fair value of our employee stock options. Under the modified prospective method, we record compensation cost related to unvested stock awards as of December 31, 2005 by recognizing the unamortized grant date fair value of these awards over the remaining vesting periods of those awards with no change in historical reported earnings. We estimated forfeiture rates for 2007 and 2006 based on our historical experience.

 

The Black-Scholes model incorporates assumptions to value stock-based awards. The risk-free rate of interest is the related U.S. Treasury yield curve for periods within the expected term of the option at the time of grant. The

 

ALLIS-CHALMERS ENERGY INC.

 

Notes to Consolidated Financial Statements — (Continued)

 

dividend yield on our common stock is assumed to be zero as we have historically not paid dividends and have no current plans to do so in the future. The expected volatility is based on historical volatility of our common stock.

 

Prior to January 1, 2006, we accounted for our stock-based compensation using Accounting Principle Board Opinion No. 25 (“APB No. 25”). Under APB No. 25, compensation expense is recognized for stock options with an exercise price that is less than the market price on the grant date of the option. For stock options with exercise prices at or above the market value of the stock on the grant date, we adopted the disclosure-only provisions of SFAS No. 123. We also adopted the disclosure-only provisions of SFAS No. 123 for the stock options granted to our employees and directors. Accordingly, no compensation cost was recognized under APB No. 25. Our net income for the years ended December 31, 2007 and 2006 includes approximately $4.9 million and $3.4 million of compensation costs related to share-based payments, respectively. The tax benefit recorded in association with the share-based payments was $1.7 million and $6.4 million for the years-ended December 31, 2007 and 2006, respectively. As of December 31, 2007 there is $16.3 million of unrecognized compensation expense related to non-vested stock based compensation grants.

 

Had compensation expense for the options granted been recorded based on the fair value at the grant date for the options, consistent with the provisions of SFAS 123, our net income and net income per common share for the year ended December 31, 2005 would have been decreased to the pro forma amounts indicated below (in thousands, except per share amounts):

 

 

Options were granted in 2007, 2006 and 2005. See Note 10 for further disclosures regarding stock options. The following assumptions were applied in determining the compensation costs:

 

 

Segments of an Enterprise and Related Information

 

We disclose the results of our segments in accordance with SFAS No. 131, Disclosures About Segments Of An Enterprise And Related Information (“SFAS No. 131”). We designate the internal organization that is used by management for allocating resources and assessing performance as the source of our reportable segments. SFAS No. 131 also requires disclosures about products and services, geographic areas and major customers. Please see Note 14 for further disclosure of segment information in accordance with SFAS No. 131.

 

ALLIS-CHALMERS ENERGY INC.

 

Notes to Consolidated Financial Statements — (Continued)

 

Income Per Common Share

 

We compute income per common share in accordance with the provisions of SFAS No. 128, Earnings Per Share (“SFAS No. 128”). SFAS No. 128 requires companies with complex capital structures to present basic and diluted earnings per share. Basic earnings per share are computed on the basis of the weighted average number of shares of common stock outstanding during the period. Diluted earnings per share is similar to basic earnings per share, but presents the dilutive effect on a per share basis of potential common shares (e.g., convertible preferred stock, stock options, etc.) as if they had been converted. Restricted stock grants are legally considered issued and outstanding, but are included in basic and diluted earnings per share only to the extent that they are vested. Unvested restricted stock is included in the computation of diluted earnings per share using the treasury stock method. Potential dilutive common shares that have an anti-dilutive effect (e.g., those that increase income per share) are excluded from diluted earnings per share.

 

The components of basic and diluted earnings per share are as follows (in thousands, except per share amounts):

 

 

Reclassification

 

Certain prior period balances have been reclassified to conform to current year presentation.

 

New Accounting Pronouncements

 

In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements (“SFAS 157”). SFAS 157 clarifies the principle that fair value should be based on the assumptions that market participants would use when pricing an asset or liability and establishes a fair value hierarchy that prioritizes the information used to develop those assumptions. Under the standard, fair value measurements would be separately disclosed by level within the fair value hierarchy. SFAS 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years, with early adoption permitted. Subsequently, the FASB provided for a one-year deferral of the provisions of SFAS 157 for non-financial assets and liabilities that are recognized or disclosed at fair value in the consolidated financial statements on a non-recurring basis. We

 

ALLIS-CHALMERS ENERGY INC.

 

Notes to Consolidated Financial Statements — (Continued)

 

believe that the adoption of SFAS 157 will not have a material impact on our financial position, results of operations or cash flows.

 

In December 2007, the FASB issued SFAS No. 141(R), Business Combinations (“SFAS 141(R)”). This statement retains the fundamental requirements in SFAS No. 141, “Business Combinations” that the acquisition method of accounting be used for all business combinations and expands the same method of accounting to all transactions and other events in which one entity obtains control over one or more other businesses or assets at the acquisition date and in subsequent periods. This statement replaces SFAS No. 141 by requiring measurement at the acquisition date of the fair value of assets acquired, liabilities assumed and any non-controlling interest. Additionally, SFAS 141(R) requires that acquisition-related costs, including restructuring costs, be recognized as expense separately from the acquisition. SFAS 141(R) applies prospectively to business combinations for fiscal years beginning after December 15, 2008. We will adopt SFAS 141(R) beginning January 1, 2009 and apply to future acquisitions.

 

In February 2007, the FASB issued Statement No. 159, The Fair Value Option for Financial Assets and Financial Liabilities (“SFAS 159”), which permits entities to elect to measure many financial instruments and certain other items at fair value. Upon adoption of SFAS 159, an entity may elect the fair value option for eligible items that exist at the adoption date. Subsequent to the initial adoption, the election of the fair value option should only be made at the initial recognition of the asset or liability or upon a re-measurement event that gives rise to the new-basis of accounting. All subsequent changes in fair value for that instrument are reported in earnings. SFAS 159 does not affect any existing accounting literature that requires certain assets and liabilities to be recorded at fair value nor does it eliminate disclosure requirements included in other accounting standards. SFAS 159 is effective as of the beginning of each reporting entity’s first fiscal year that begins after November 15, 2007. We are currently evaluating the provisions of SFAS 159 and have not yet determined the impact, if any, on our financial statements.

 

In December 2007, the FASB issued SFAS No. 160, “Non-controlling Interests in Consolidated Financial Statements — an amendment of ARB No. 51” (“SFAS 160”). SFAS 160 requires (i) that non-controlling (minority) interests be reported as a component of shareholders’ equity, (ii) that net income attributable to the parent and to the non-controlling interest be separately identified in the consolidated statement of operations, (iii) that changes in a parent’s ownership interest while the parent retains its controlling interest be accounted for as equity transactions, (iv) that any retained non-controlling equity investment upon the deconsolidation of a subsidiary be initially measured at fair value, and (v) that sufficient disclosures are provided that clearly identify and distinguish between the interests of the parent and the interests of the non-controlling owners. SFAS 160 is effective for annual periods beginning after December 15, 2008 and should be applied prospectively. The presentation and disclosure requirements of the statement shall be applied retrospectively for all periods presented. We believe the adoption of SFAS 160 will not have a material impact on our financial position or results of operations.

 

 

Medical And Life

 

Pursuant to the Plan of Reorganization that was confirmed by the Bankruptcy Court after acceptances by our creditors and stockholders and was consummated on December 2, 1988, we assumed the contractual obligation to Simplicity Manufacturing, Inc. (SMI) to reimburse SMI for 50% of the actual cost of medical and life insurance claims for a select group of retirees (SMI Retirees) of the prior Simplicity Manufacturing Division of Allis-Chalmers. The actuarial present value of the expected retiree benefit obligation is determined by an actuary and is the amount that results from applying actuarial assumptions to (1) historical claims-cost data, (2) estimates for the time value of money (through discounts for interest) and (3) the probability of payment (including decrements for death, disability, withdrawal, or retirement) between today and expected date of benefit payments. As of December 31, 2007 and 2006, we have post-retirement benefit obligations of $31,000 and $304,000, respectively.

 

ALLIS-CHALMERS ENERGY INC.

 

Notes to Consolidated Financial Statements — (Continued)

 

401(k) Savings Plan

 

On June 30, 2003, we adopted the 401(k) Profit Sharing Plan (the “Plan”). The Plan is a defined contribution savings plan designed to provide retirement income to our eligible employees. The Plan is intended to be qualified under Section 401(k) of the Internal Revenue Code of 1986, as amended. It is funded by voluntary pre-tax contributions from eligible employees who may contribute a percentage of their eligible compensation, limited and subject to statutory limits. The Plan is also funded by discretionary matching employer contributions from us. Eligible employees cannot participate in the Plan until they have attained the age of 21 and completed three-months of service with us. Each participant is 100% vested with respect to the participants’ contributions while our matching contributions are vested over a three-year period in accordance with the Plan document. Contributions are invested, as directed by the participant, in investment funds available under the Plan. Matching contributions of approximately $1.8 million, $735,000 and $114,000 were paid in 2007, 2006 and 2005, respectively.

 

 

On April 1, 2005, we acquired 100% of the outstanding stock of Delta Rental Service, Inc., or Delta, for approximately $4.6 million in cash, 223,114 shares of our common stock and two promissory notes totaling $350,000. The purchase price was allocated to fixed assets and inventory. Delta, located in Lafayette, Louisiana, was a rental tool company providing specialty rental items to the oil and gas industry such as spiral heavy weight drill pipe, test plugs used to test blow-out preventors, well head retrieval tools, spacer spools and assorted handling tools. The results of Delta since the acquisition are included in our Rental Services segment.

 

On May 1, 2005, we acquired 100% of the outstanding capital stock of Capcoil Tubing Services, Inc., or Capcoil, for approximately $2.7 million in cash, 168,161 shares of our common stock and the payment or assumption of approximately $1.3 million of debt. Capcoil, located in Kilgore, Texas, is engaged in downhole well servicing by providing coil tubing services to enhance production from existing wells. Goodwill of $184,000 and other identifiable intangible assets of $1.4 million were recorded in connection with the acquisition. The results of Capcoil since the acquisition are included in our Production Services segment.

 

On July 11, 2005, we acquired the compressed air drilling assets of W.T Enterprises, Inc., or W.T., based in South Texas, for $6.0 million in cash. The equipment includes compressors, boosters, mist pumps and vehicles. Goodwill of $82,000 and other identifiable intangible assets of $1.5 million were recorded in connection with the acquisition. The results of the W.T. assets since their acquisition are included in our Underbalanced Drilling segment.

 

On July 11, 2005, we acquired from M-I L.L.C. (“M-I”) its 45% interest in AirComp and subordinated note in the principal amount of $4.8 million issued by AirComp, for which we paid M-I $7.1 million in cash and issued to M-I a $4.0 million subordinated note bearing interest at 5% per annum. As a result, we now own 100% of AirComp. The results of AirComp are included in our Underbalanced Drilling segment.

 

Effective August 1, 2005, we acquired 100% of the outstanding capital stock of Target Energy Inc., or Target, for approximately $1.3 million in cash and forgiveness of a lease receivable of approximately $0.6 million. The purchase price was allocated to the fixed assets of Target. The results of Target are included in our directional and horizontal drilling segment as their Measure While Drilling equipment is utilized in that segment.

 

On September 1, 2005, we acquired the casing and tubing service assets of Patterson Services, Inc. for approximately $15.6 million. These assets are located in Corpus Christi, Texas; Kilgore, Texas; Lafayette, Louisiana and Houma, Louisiana. The results of these assets since their acquisition are included in our Tubular Services segment.

 

ALLIS-CHALMERS ENERGY INC.

 

Notes to Consolidated Financial Statements — (Continued)

 

Effective January 1, 2006, we acquired 100% of the outstanding stock of Specialty Rental Tools, Inc., or Specialty, for approximately $95.3 million in cash. In addition, approximately $588,000 of costs were incurred in relation to the Specialty acquisition. Specialty, located in Lafayette, Louisiana, was engaged in the rental of high quality drill pipe, heavy weight spiral drill pipe, tubing work strings, blow-out preventors, choke manifolds and various valves and handling tools for oil and natural gas drilling. The following table summarizes the allocation of the purchase price and related acquisition costs to the estimated fair value of the assets acquired and liabilities assumed at the date of acquisition (in thousands):

 

 

Specialty’s historical property and equipment values were increased by approximately $71.6 million based on third-party valuations. The results of Specialty since the acquisition are included in our Rental Services segment.

 

Effective April 1, 2006, we acquired 100% of the outstanding stock of Rogers Oil Tools, Inc., or Rogers, based in Lafayette, Louisiana, for a total consideration of approximately $13.7 million, which includes approximately $11.3 million in cash, $1.6 million in our common stock and a $750,000 three-year promissory note. In addition, approximately $380,000 of costs were incurred in relation to the Rogers acquisition. Rogers sells, services and rents power drill pipe tongs and accessories and rental tongs for snubbing and well control applications. Rogers also provides specialized tong operators for rental jobs. The following table summarizes the allocation of the purchase price and related acquisition costs to the estimated fair value of the assets acquired and liabilities assumed at the date of acquisition (in thousands):

 

 

Rogers’ historical property and equipment values were increased by approximately $8.4 million based on third-party valuations. Intangible assets include approximately $2.4 million assigned to goodwill, $1.2 million assigned to patents, $1.1 million assigned to customer list and $150,000 assigned to non-compete based on third-party valuations and employment contracts. The amortizable intangibles have a weighted-average useful life of 10.5 years. The results of Rogers since the acquisition are included in our Tubular Services segment.

 

ALLIS-CHALMERS ENERGY INC.

 

Notes to Consolidated Financial Statements — (Continued)

 

Effective August 14, 2006, we acquired 100% of the outstanding stock of DLS, based in Argentina, for a total consideration of approximately $114.5 million, which includes approximately $93.7 million in cash, $38.1 million in our common stock, less approximately $17.3 million of debt assigned to us. In addition, approximately $3.4 million of costs were incurred in relation to the DLS acquisition. DLS operates a fleet of 51 rigs, including 20 drilling rigs, 18 workover rigs and 12 pulling rigs in Argentina and one drilling rig in Bolivia. The following table summarizes the allocation of the purchase price and related acquisition costs to the estimated fair value of the assets acquired and liabilities assumed at the date of acquisition (in thousands):

 

 

DLS’ historical property and equipment values were increased by approximately $22.7 million based on third-party valuations. The results of DLS since the acquisition are included in our International Drilling segment.

 

On October 16, 2006, we acquired 100% of the outstanding stock of Petro Rental, based in Lafayette, Louisiana, for a total consideration of approximately $33.6 million, which includes approximately $20.2 million in cash, $3.8 million in our common stock and repaid $9.6 million of existing Petro Rental debt. In addition, approximately $82,000 of costs were incurred in relation to the Petro-Rental acquisition. Petro-Rental provides a variety of production-related rental tools and equipment and services, including wire line services and equipment, land and offshore pumping services and coiled tubing. The following table summarizes the allocation of the purchase price and related acquisition costs to the estimated fair value of the assets acquired and liabilities assumed at the date of acquisition (in thousands):

 

 

Petro Rental’s historical property and equipment values were increased by approximately $13.4 million based on third-party valuations. Intangible assets include approximately $3.6 million assigned to goodwill and $2.2 million assigned to customer relationships based on third-party valuations. The amortizable intangibles have a weighted-average useful life of 10 years. The results of Petro-Rental since the acquisition are included in our Production Services segment.

 

ALLIS-CHALMERS ENERGY INC.

 

Notes to Consolidated Financial Statements — (Continued)

 

Effective December 1, 2006, we acquired 100% of the outstanding stock of Tanus, based in Argentina, for a total consideration of $2.5 million. In addition, approximately $17,000 of costs were incurred in relation to the Tanus acquisition. Tanus is engaged in the research and manufacturing of additives for the oil, natural gas and water well drilling and completion fluids in Argentina. The following table summarizes the allocation of the purchase price and related acquisition costs to the estimated fair value of the assets acquired and liabilities assumed at the date of the acquisition (in thousands).

 

 

The results of Tanus are reported with DLS under our International Drilling segment.

 

On December 18, 2006, we acquired substantially all of the assets of Oil & Gas Rental Services, Inc, or OGR, based in Morgan City, Louisiana, for a total consideration of approximately $342.4 million, which includes approximately $291.0 million in cash, and $51.4 million in our common stock. In addition, approximately $3.0 million of costs were incurred in relation to the acquisition of the assets of OGR The following table summarizes the allocation of the purchase price and related acquisition costs to the estimated fair value of the assets acquired at the date of acquisition (in thousands):

 

 

OGR’s historical property and equipment values were increased by approximately $168.9 million based on third-party valuations. Intangible assets include approximately $106.1 million assigned to goodwill, $22.0 million to customer relations, $831,000 to patents and $35,000 assigned to employment agreements based on third-party valuations. The amortizable intangibles have a weighted-average useful life of 10.1 years. The results of the OGR assets since their acquisition are included in our Rental Services segment.

 

On June 29 2007, we acquired Coker Directional, Inc., or Coker, for a total consideration of approximately $3.9 million, which includes approximately $3.6 million in cash and a promissory note for $350,000. In addition, approximately $5,000 of costs were incurred in relation to the Coker acquisition. The following table summarizes the preliminary allocation of the purchase price and related acquisition costs to the estimated fair value of the assets acquired and liabilities assumed at the date of the acquisition (in thousands):

 

 

Intangible assets include approximately $1.8 million assigned to goodwill and $2.1 million assigned to customer relationships and non-compete. The amortizable intangibles have a weighted-average useful life of 9.4 years. The results of Coker since the acquisition are included in our Directional Drilling segment. We do not expect any material differences from the preliminary allocation of the purchase price and the final purchase price allocations.

 

ALLIS-CHALMERS ENERGY INC.

 

Notes to Consolidated Financial Statements — (Continued)

 

On July 26, 2007, we acquired Diggar Tools, LLC, or Diggar, for a total consideration of approximately $10.3 million, which includes approximately $6.7 million in cash, a promissory note for $750,000 and payment of approximately $2.8 million of existing Diggar debt. In addition, approximately $29,000 of costs were incurred in relation to the Diggar acquisition. The following table summarizes the preliminary allocation of the purchase price and related acquisition costs to the estimated fair value of the assets acquired at the date of acquisition (in thousands):

 

 

Diggar’s historical property and equipment values were increased by approximately $3.4 million based on third-party valuations. Intangible assets include approximately $2.7 million assigned to goodwill. The results of Diggar since the acquisition are included in our Directional Drilling segment. We do not expect any material differences from the preliminary allocation of the purchase price and the final purchase price allocations.

 

On October 23, 2007, we acquired Rebel for a total consideration of approximately $7.3 million, which includes approximately $5.0 million in cash, promissory notes for an aggregate of $500,000, payment of approximately $1.5 million of existing Rebel debt and the deposit of $305,000 in escrow to cover distributions owed under the Rebel Defined Benefit Pension Plan & Trust. In addition, approximately $214,000 of costs were incurred in relation to the Rebel acquisition. The following table summarizes the preliminary allocation of the purchase price and related acquisition costs to the estimated fair value of the assets acquired at the date of acquisition (in thousands):

 

 

Rebel’s historical property and equipment values were increased by approximately $8.5 million based on third-party valuations. Intangible assets include approximately $461,000 assigned to goodwill and $683,000 assigned to customer relations. The amortizable intangibles have a useful life of 15 years. The results of Rebel since the acquisition are included in our Tubular services segment. We do not expect any material differences from the preliminary allocation of the purchase price and the final purchase price allocations.

 

ALLIS-CHALMERS ENERGY INC.

 

Notes to Consolidated Financial Statements — (Continued)

 

On November 1, 2007, we acquired substantially all the assets Diamondback Oilfield Services, Inc. or Diamondback, for a total consideration of approximately $23.1 million in cash. Approximately $89,000 of costs were incurred in relation to the Diamondback acquisition. The following table summarizes the preliminary allocation of the purchase price and related acquisition costs to the estimated fair value of the assets acquired at the date of acquisition (in thousands):

 

 

Diamondback’s historical property and equipment values were increased by approximately $2.0 million based on third-party valuations. Intangible assets include approximately $7.6 million assigned to goodwill, $650,000 assigned to non-compete, $620,000 assigned to trade name and $3.4 million assigned to customer relations based on third-party valuations. The amortizable intangibles have a weighted-average useful life of 13.3 years. The sellers are entitled to a future cash earn-out payment upon the business attaining certain earning objectives. The results of the Diamondback assets since their acquisition are included in our Directional Drilling segment. We do not expect any material differences from the preliminary allocation of the purchase price and the final purchase price allocations.

 

The acquisitions were accounted for using the purchase method of accounting. The results of operations of the acquired entities since the date of acquisition are included in our consolidated income statement.

 

On June 29, 2007, we sold our capillary tubing units and related equipment for approximately $16.3 million. We reported a gain of approximately $8.9 million. The assets sold represented a small portion of our Production Services segment.

 

The following unaudited pro forma consolidated summary financial information for the year ended December 31, 2006 illustrates the effects of the acquisitions and the related public offerings of debt and equity for Rogers, DLS, Petro-Rental and OGR as if the acquisitions occurred as of January 1, 2006, based on the historical results of the acquisitions. The following unaudited pro forma consolidated summary financial information for the year ended December 31, 2005 illustrates the effects of the acquisitions and the related public offerings of debt and equity for Delta, Capcoil, W.T., the minority interest in AirComp, Specialty, Rogers, DLS, Petro-Rental and OGR as if the acquisitions had occurred as of January 1, 2005, based on the historical results of the acquisitions. The historical results for OGR are based on their historical year end of October 31 (in thousands, except per share amounts):

 

 

ALLIS-CHALMERS ENERGY INC.

 

Notes to Consolidated Financial Statements — (Continued)

 

 

Inventories are comprised of the following as of December 31 (in thousands):

 

 

 

Property and equipment is comprised of the following as of December 31 (in thousands):

 

 

The net book value of equipment recorded under capital leases was $285,000 and $1.0 million as of December 31, 2007 and 2006, respectively.

 

ALLIS-CHALMERS ENERGY INC.

 

Notes to Consolidated Financial Statements — (Continued)

 

Other intangible assets are as follows as of December 31 (in thousands):

 

 

 

Amortization expense related to other intangibles was $4.1 million, $1.9 million and $1.5 million for the years ended December 31, 2007, 2006 and 2005, respectively. Future amortization of intangible assets at December 31, 2007 is as follows (in thousands):

 

 

 

We had income before income taxes of $41.7 million, $35.9 million and $8.5 million for U.S. tax purposes for the years ended December 31, 2007, 2006 and 2005, respectively. We also had income before income taxes of $37.6 million and $11.1 million reported in non-U.S. countries for the years ended December 31, 2007 and 2006, respectively. We treat the withholding taxes incurred by our U.S. subsidiaries in foreign countries as foreign tax, and we anticipate using those tax payments to offset U.S. tax.

 

ALLIS-CHALMERS ENERGY INC.

 

Notes to Consolidated Financial Statements — (Continued)