UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

(Mark One)

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

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

Commission File Number: 000-51435

SUPERIOR WELL SERVICES, INC.

Delaware		20-2535684
(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		Identification No.)

1380 Rt. 286 East, Suite #121
Indiana, Pennsylvania 15701
(Address of principal executive offices)
(Zip Code)

(724) 465-8904
(Registrant’s telephone number, including area code)

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

     Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o       No o

     Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.

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

     Indicate by check mark if the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

     Yes o       No þ

     As of May 4, 2010, there were outstanding 30,832,174 shares of the registrant’s common stock, par value $.01, which is the only class of common or voting stock of the registrant.

 

 

SUPERIOR WELL SERVICES, INC. QUARTERLY REPORT ON FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2010

TABLE OF CONTENTS

PART I — FINANCIAL INFORMATION			1
Item 1. Financial Statements			1
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			20
Item 3. Quantitative and Qualitative Disclosures about Market Risk			36
Item 4. Controls and Procedures			36
PART II – OTHER INFORMATION			37
Item 1. Legal Proceedings			37
Item 1A. Risk Factors			37
Item 2. Unregistered Sale of Equity Securities			37
Item 6. Exhibits			37

PART I — FINANCIAL INFORMATION

Item 1. Financial Statements.

SUPERIOR WELL SERVICES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)

		December 31,				March 31,
		2009				2010
		(in thousands, except per share data)
Current assets:
Cash and cash equivalents		$	25			$	23
Trade accounts receivable, net of allowance of $5,800 and $4,196, respectively			69,492				88,063
Inventories			24,991				25,300
Prepaid expenses and other current assets			2,369				2,090
Advances on materials for future delivery			3,717				3,717
Income taxes receivable			36,044				35,900
Deferred income taxes			4,203				2,589
Total current assets			140,841				157,682
Property, plant and equipment, net			409,552				395,420
Intangible assets, net of accumulated amortization of $5,244 and $5,787, respectively			7,518				6,976
Other assets			12,242				11,643
Total assets		$	570,153			$	571,721
Current liabilities:
Accounts and construction payable-trade		$	26,849			$	41,862
Current portion of long-term obligations			2,022				1,364
Advanced payments on servicing contracts			87				247
Accrued wages and health benefits			3,581				2,885
Accrued interest			4,356				4,432
Other accrued liabilities			5,033				6,317
Total current liabilities			41,928				57,107
Long-term debt			163,594				164,407
Deferred income taxes			37,510				31,371
Long-term capital leases			275				634
Asset retirement obligation			415				422
Stockholders’ Equity:
Preferred stock, non-voting, par $0.01 per share, 10,000,000 shares authorized Series A 4% Convertible Preferred stock, non-voting, 75,000 shares issued at December 31, 2009 (liquidation preference $75 million)			1				1
Common stock, voting, par $0.01 per share, 70,000,000 shares authorized, 30,688,137 and 30,835,234 shares issued at December 31, 2009 and March 31, 2010			305				304
Additional paid-in-capital			301,103				301,855
Retained earnings			25,022				15,620
Total stockholders’ equity			326,431				317,780
Total liabilities and stockholders’ equity		$	570,153			$	571,721

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

SUPERIOR WELL SERVICES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)

		Three Months Ended
		March 31,
		2009				2010
		(in thousands, except per share data)
Revenue		$	122,281			$	123,340
Cost of revenue			125,320				122,095
Gross profit (loss)			(3,039	)			1,245
Selling, general and administrative expenses			16,055				11,656
Operating income (loss)			(19,094	)			(10,411	)
Interest expense			3,176				2,902
Other (expense) income, net			(193	)			136
Income (loss) before income taxes			(22,463	)			(13,177	)
Income taxes
Current			(12,286	)			—
Deferred			4,534				(4,525	)
			(7,752	)			(4,525	)
Net income (loss) before dividends on preferred stock		$	(14,711	)		$	(8,652	)
Dividends on preferred stock			(750	)			(750	)
Net income (loss) available to common stockholders		$	(15,461	)		$	(9,402	)
Earnings (loss) per common share:
Basic		$	(0.67	)		$	(0.31	)
Fully diluted		$	(0.67	)		$	(0.31	)
Weighted average shares outstanding — basic			23,204,960				30,186,377
Weighted average shares outstanding — diluted			26,204,960				33,328,817

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

SUPERIOR WELL SERVICES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY
(Unaudited)

		Preferred				Common				Additional				Retained
		Stock				Stock				Paid-in				Earnings				Total
										(in thousands)
BALANCE, DECEMBER 31, 2008		$	1			$	236			$	229,741			$	107,637			$	337,615
Net loss			—				—				—				(14,711	)			(14,711	)
Issuance of restricted stock awards			—				2				184				—				186
Restricted stock retired/forfeited			—				—				(85	)			—				(85	)
Share-based compensation			—				—				737				—				737
Preferred Stock dividends			—				—				—				(750	)			(750	)
BALANCE, MARCH 31, 2009		$	1			$	238			$	230,577			$	92,176			$	322,992
BALANCE, DECEMBER 31, 2009		$	1			$	305			$	301,103			$	25,022			$	326,431
Net loss			—				—				—				(8,652	)			(8,652	)
Issuance of restricted stock awards			—				2				197				—				199
Restricted stock retired/forfeited			—				(3	)			(310	)			—				(313	)
Share-based compensation			—				—				865				—				865
Preferred stock dividends			—				—				—				(750	)			(750	)
BALANCE, MARCH 31, 2010		$	1			$	304			$	301,855			$	15,620			$	317,780

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

SUPERIOR WELL SERVICES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

		Three months ended March 31,
		2009				2010
		(in thousands)
Cash flows from operations:
Net loss		$	(14,711	)		$	(8,652	)
Adjustments to reconcile net loss to net cash provided by (used in) operations:
Deferred income taxes			4,534				(4,525	)
Depreciation, amortization and accretion			17,485				19,787
Provision for bad debts			537				825
Loss on disposal of equipment			214				88
Stock based compensation			737				865
Changes in assets and liabilities:
Trade accounts receivable			7,496				(19,395	)
Advance on materials for future delivery			599				499
Inventory			984				(309	)
Prepaid expenses and other assets			596				279
Income tax receivable			(12,285	)			144
Accounts payable			(13,299	)			13,806
Advance payments on servicing contracts			156				160
Accrued wages and health benefits			187				(696	)
Other accrued liabilities			(82	)			1,360
Net cash (used in) provided by operations			(6,852	)			4,236
Cash flows from investing:
Expenditure for property, plant and equipment, net of construction payables			(9,356	)			(5,430	)
Acquisition of businesses, net of cash acquired			(1,873	)			—
Proceeds (expenditures) for other assets			169				99
Proceeds from sale of property, plant and equipment			1,908				1,443
Net cash used in investing			(9,152	)			(3,888	)
Cash flows from financing:
Principal payments on long-term debt			(53,214	)			(35,427	)
Proceeds from long-term borrowings			71,019				36,240
Issuance/retirement of restricted stock, net			101				(114	)
Payment on capital lease obligations			(290	)			(299	)
Payment of preferred dividends			(750	)			(750	)
Net cash provided by (used in) financing			16,866				(350	)
Net increase (decrease) in cash and cash equivalents			862				(2	)
Cash and cash equivalents, beginning of period			1,637				25
Cash and cash equivalents, end of period		$	2,499			$	23
Supplemental disclosure of cash flow data:
Interest paid		$	1,727			$	2,815
Income taxes paid (received)			(1	)			(144	)

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

SUPERIOR WELL SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

1. Organization

     Superior Well Services, Inc. (“Superior,” “we” or “us”) was formed as a Delaware corporation on March 2, 2005 for the purpose of serving as the parent holding company for Superior GP, L.L.C. (“Superior GP”), Superior Well Services, Ltd. (“Superior Well”) and Bradford Resources, Ltd. (“Bradford”). In May 2005, Superior and the partners of Superior Well and Bradford entered into a contribution agreement that resulted in the partners of Superior Well and Bradford contributing their respective partnership interests to Superior in exchange for shares of common stock of Superior (the “Contribution Agreement”). In December 2006, Bradford was merged into Superior Well. Superior Well is a Pennsylvania limited partnership that became a wholly owned subsidiary of Superior in connection with its initial public common stock offering.

     In November 2008, Superior purchased the pressure pumping, fluid logistics and completion, production and rental tool assets of Diamondback Energy Holdings, LLC (“Diamondback”). In connection with the asset acquisition, Superior formed SWSI Fluids, LLC to acquire and operate the fluid logistics assets. SWSI Fluids, LLC is a wholly owned subsidiary of Superior.

     Superior Well provides a wide range of well services to oil and gas companies, primarily technical pumping and down-hole surveying services, in many of the major oil and natural gas producing regions of the United States.

2. Summary of Significant Accounting Policies

     Basis of Presentation

     The consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). These financial statements reflect all adjustments that, in our opinion, are necessary to fairly present our financial position and results of operations. Significant intercompany accounts and transactions have been eliminated in consolidation.

     The accompanying consolidated financial statements include the accounts of Superior and its wholly-owned subsidiaries Superior Well, Superior GP and SWSI Fluids LLC. Superior Well and Bradford (“Partnerships”), prior to the effective date of the Contribution Agreement, were entities under common control arising from common direct or indirect ownership of each. The transfer of the Partnerships assets and liabilities to Superior (see Note 1) represented a reorganization of entities under common control and was accounted for at historical cost. Prior to the reorganization, the Partnerships were not subject to federal and state corporate income taxes.

     Estimates and Assumptions

     Superior uses certain estimates and assumptions that affect reported amounts and disclosures. These estimates are based on judgments, probabilities and assumptions that are believed to be reasonable but inherently uncertain and unpredictable. Assumptions may be incomplete or inaccurate, and unanticipated events and circumstances may occur. Superior is subject to risks and uncertainties that may cause actual results to differ from estimated amounts.

     Cash and Cash Equivalents

     All cash and cash equivalents are stated at cost, which approximates market. Superior considers all highly liquid investments purchased with a maturity of three months or less to be cash equivalents. Superior maintains cash at various financial institutions that may exceed federally insured amounts.

     Trade Accounts Receivable

     Accounts receivable are carried at the amount owed by customers. Superior grants credit to all qualified customers, which are mainly independent oil and natural gas companies. Management periodically reviews accounts receivable for credit risks resulting from changes in the financial condition of its customers. Once an account is deemed not to be collectible, the remaining balance is charged to the reserve account. For the three

SUPERIOR WELL SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

month periods ended March 31, 2009 and 2010, Superior recorded a provision for uncollectible accounts receivable of $592,000 and $825,000, respectively.

     Assets Held For Sale

     Superior classifies certain assets as held for sale based on management having the authority and intent of entering into commitments for sale transactions expected to close in the next twelve months. When management identifies an asset held for sale, Superior estimates the net selling price of such an asset. If the net selling price is less than the carrying amount of the asset, a reserve for loss is established. Fair value is determined at prevailing market conditions, appraisals or current estimated net sales proceeds from pending offers.

     Advances on Material for Future Delivery

     In January 2010, Superior amended its take-or-pay contract with Preferred Rocks USS, Inc. to purchase fracturing sand through December 2015. In connection with the take-or-pay contract Superior advanced $15 million for materials that will be delivered in the future. Under the amended terms of the take-or-pay contract, Superior earns a 6% interest rate on the unused portion of the advance on materials. The advance on materials for future delivery will be used to offset future purchase commitments under the take-or-pay contract. At March 31, 2010, the portion of the advance expected to offset future purchases within the next twelve months amounted to $3.7 million and is reflected in current assets. Other assets include $9.4 million for advances expected to offset future purchases after one year.

     Property, Plant and Equipment

     Superior’s property, plant and equipment are stated at cost less accumulated depreciation. The costs are depreciated using the straight-line method over their estimated useful lives. The estimated useful lives range from 15 to 30 years for building and improvements, range from 5 to 15 years for disposal wells and related equipment and range from 5 to 10 years for equipment and vehicles. Depreciation expense, excluding intangible amortization, amounted to $16.9 million and $19.2 million for the three months ended March 31, 2009 and 2010, respectively.

     Repairs and maintenance costs that do not extend the useful lives of the asset are expensed in the period incurred. Gain or loss resulting from the retirement or other disposition of assets is included in income.

     Superior reviews long-lived assets for impairment whenever there is evidence that the carrying value of such assets may not be recoverable. The review consists of comparing the carrying value of the assets with the assets’ expected future undiscounted cash flows. An impairment loss would be recognized when estimated future cash flows expected to result from the use of the assets and their eventual dispositions are less than the assets’ carrying value. Estimates of expected future cash flows represent management’s best estimate based on reasonable and supportable assumptions.

     Revenue Recognition

     Superior’s revenue is comprised principally of service revenue. Product sales represent approximately 1% of total revenues. Services and products are generally sold based on fixed or determinable pricing agreements with the customer and generally do not include rights of return. Service revenue is recognized, net of discount, when the services are provided and collectability is reasonably assured. Substantially all of Superior’s services performed for customers are completed at the customer’s site within one day. Superior recognizes revenue from product sales when the products are delivered to the customer and collectability is reasonably assured. Products are delivered and used by our customers in connection with the performance of our cementing services. Product sale prices are determined by published price lists provided to our customers.

     Inventories

     Inventories are stated at the lower of cost or market. Cost primarily represents invoiced costs. We regularly review inventory quantities on hand and record provisions for excess or obsolete inventory based primarily on historical usage, estimated product demand and technological developments.

SUPERIOR WELL SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

     Insurance Expense

     Superior partially self-insures employee health insurance plan costs. The estimated costs of claims under this self-insurance program are accrued as the claims are incurred (although actual settlement of the claims may not be made until future periods) and may subsequently be revised based on developments relating to such claims. The self-insurance accrual is estimated based upon our historical experience, as well as any known unpaid claims activity. Judgment is required to determine the appropriate accrual levels for claims incurred but not yet received and paid. The accrual estimates are based primarily upon recent historical experience adjusted for employee headcount changes. Historically, the lag time between the occurrence of an insurance claim and the related payment has been approximately one to two months and the differences between estimates and actuals have not been material. The estimates could be affected by actual claims being significantly different. Presently, Superior maintains an insurance policy that covers claims in excess of $150,000 per employee.

     Income Taxes

     Superior recognizes deferred tax liabilities and assets for the expected future tax consequences of events that have been recognized in Superior’s financial statements or tax returns. Using this method, deferred tax liabilities and assets were determined based on the difference between the financial carrying amounts and tax bases of assets and liabilities using estimated effective tax rates. Prior to becoming wholly-owned subsidiaries of Superior, Superior Well and Bradford were not taxable entities for federal or state income tax purposes and, accordingly, were not subject to federal or state corporate income taxes. Superior’s accounting policies require that a valuation allowance be established when it is more likely than not that all or a portion of a deferred tax asset will not be realized. We evaluate the realizability of our deferred tax assets on quarterly basis and valuation allowances are provided as necessary. We have not recorded any valuation allowances as of March 31, 2010. Superior’s balance sheets at December 31, 2009 and March 31, 2010 do not include any liabilities associated with uncertain tax positions; further Superior has no unrecognized tax benefits that if recognized would change the effective tax rate.

     We file U.S. federal income tax returns and various state and local income tax returns. We are not subject to U.S. federal, state and local income tax examinations by tax authorities for years before 2005. Superior classifies interest related to income tax expense in interest expense and penalties in general and administrative expense. Interest and penalties for the three months ended March 31, 2009 and 2010 were insignificant in each period. We are subject to U.S. federal income tax examinations for years after 2005 and we are subject to various state and local tax examinations for years after 2005.

     Asset Retirement Obligations

     Superior records the fair value of an asset retirement obligation as a liability in the period in which it incurs legal obligation associated with the retirement of the assets and capitalizes an equal amount as a cost of the assets, depreciating it over the life of the assets. Subsequent to the initial measurement of the asset retirement obligation, the obligation is adjusted to reflect the passage of time, changes in the estimated future cash flows underlying the obligation, acquisition or construction of assets and settlements of obligations. In November 2008, Superior assumed asset retirement obligations, through the Diamondback asset acquisition, to plug and abandon its disposal wells at the end of their operations. Accretion expense for the three months ended March 31, 2009 and 2010 was insignificant.

     Fair Value of Financial Instruments

     In September 2006, the FASB issued accounting Topic 820, “Fair Value Measurements,” which is intended to increase consistency and comparability in fair value measurements by defining fair value, establishing a framework for measuring fair value and expanding disclosures about fair value measurements. This statement applies to other accounting pronouncements that require or permit fair value measurements and is effective for financial statements issued for fiscal years beginning after November 15, 2007 and interim periods within those fiscal years. On January 1, 2008, we adopted, without material impact on our consolidated financial statements, the provisions of Topic 820 related to financial assets and liabilities.

SUPERIOR WELL SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

     Topic 820 requires disclosure about how fair value is determined for assets and liabilities and establishes a hierarchy for which these assets and liabilities must be grouped, based on significant levels of inputs as follows:

	Level 1		quoted prices in active markets for identical assets or liabilities;
	Level 2		quoted prices in active markets for similar assets and liabilities and inputs that are observable for the asset or liability; or
	Level 3		unobservable inputs for the asset or liability, such as discounted cash flow models or valuations.

     The determination of where assets and liabilities fall within this hierarchy is based upon the lowest level of input that is significant to the fair value measurement.

     Superior’s financial instruments are not held for trading purposes.

     Acquisitions

     Assets acquired in business combinations were recorded on Superior’s consolidated balance sheets as of the respective acquisition dates based upon their estimated fair values at such dates. The results of operations of businesses acquired by Superior have been included in Superior’s consolidated statements of income since their respective dates of acquisition. The excess of the purchase price over the estimated fair values of the underlying net assets acquired, including other intangible assets was allocated to goodwill. In certain circumstances, the allocations are based upon preliminary estimates and assumptions. Accordingly, the allocations are subject to revision when we receive final information. Revisions to the fair values will be recorded by us as further adjustments to the purchase price allocations.

     Goodwill and Intangible Assets

     We perform our goodwill impairment test annually, or more frequently, if an event or circumstances would give rise to an impairment indicator. These circumstances include, but are not limited to, significant adverse changes in the business climate. Our goodwill impairment test is performed at the business segment levels, technical services and fluid logistics, as they represent our reporting units. The impairment test is a two-step process. The first step compares the fair value of a reporting unit with its carrying amount, including goodwill, and uses a future cash flow analysis based on the estimates and assumptions for our long-term business forecast. If the fair value of a reporting unit exceeds its carrying amount, the reporting unit’s goodwill is deemed to be not impaired. If the fair value of a reporting unit is less than its carrying amount, the second step of the goodwill impairment test is performed to determine the impairment loss, if any. This second step compares the implied fair value of the reporting unit’s goodwill with the carrying amount of the goodwill, and if the carrying amount of the reporting unit’s goodwill is greater than the implied fair value of that goodwill, an impairment loss is recorded for the difference. Any impairment charge would reduce earnings.

     Superior performed an assessment of goodwill at December 31, 2008 and the tests resulted in no indications of impairment. However, Superior determined a “triggering event” requiring an interim assessment had occurred at June 30, 2009 because the oil and gas services industry continued to decline and its net book value had been substantially in excess of its market capitalization during the second quarter of 2009.

     To estimate the fair value of the business segments, Superior used a weighted-average approach of two commonly used valuation techniques; a discounted cash flow method and a similar transaction method. Superior’s management assigned a weight to the results of each of these methods based on the facts and circumstances that are in existence for that testing period. During the second quarter of 2009, because of overall economic downturn, management assigned more weighting to the discounted cash flow method than the similar transaction method. Given the continued deterioration of the general economic and oil service industry conditions during 2009, management believed that similar transactions may not be as useful because the valuations may reflect distressed sales conditions. Accordingly, the similar transaction weighting was reduced to 10% during the second quarter of 2009.

SUPERIOR WELL SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

     In addition to the estimates made by management regarding the weighting of the various valuation techniques, the creation of the techniques themselves requires significant estimates and assumptions to be made by management. The discounted cash flow method, which is assigned the highest weight by management, requires assumptions about future cash flows, future growth rates and discount rates. The assumptions about future cash flows and growth rates are based on our forecasts and strategic plans, as well as the beliefs of management about future activity levels. In applying the discounted cash flow 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 discounted to present value to derive an indication of value of the business enterprise.

     Superior’s intangible assets consist of $7.0 million of customer relationships and non-compete agreements that are amortized over their estimated useful lives which range from three to five years. For the three months ended March 31, 2009 and 2010, Superior recorded amortization expense of $582,000 and $543,000, respectively.

     Valuation of Finite-Lived Intangible and Tangible Assets

     Superior performs impairment tests when a possible impairment may exist. Unlike goodwill and indefinite-lived intangible assets, fixed assets and finite-lived intangibles are not tested for impairment on a recurring basis, but only when circumstances or events indicate a possible impairment may exist. These circumstances or events are referred to as “trigger events” and examples of such trigger events include, but are not limited to, an adverse change in business conditions, a significant decrease in benefits being derived from an acquired business, or a significant disposal of a particular asset or asset class. If a trigger event occurs, an impairment test is performed based on an undiscounted cash flow analysis.

     We determined a “triggering event” requiring an assessment had occurred because the oil and gas services industry continued to decline and our net book value has been substantially in excess of our market capitalization during the second and third quarters of 2009. No impairment was indicated by this test.

     Concentration of Credit Risk

     Substantially all of Superior’s customers are engaged in the oil and gas industry. This concentration of customers may impact Superior’s overall exposure to credit risk, either positively or negatively, in that customers may be similarly affected by changes in economic and industry conditions. Two customers individually accounted for 22% and 12% our revenue for the three months ended March 31, 2009. During the three months ended March 31, 2010 no single customer accounted for more than 10% of our revenue. At December 31, 2009, two customers accounted for 23% and 12% and eight customers collectively accounted for 62% of Superior’s accounts receivable, respectively. At March 31, 2010, one customer accounted for 13% and eight customers collectively accounted for 57% of Superior’s accounts receivable, respectively.

     Share Based Compensation

     We account for equity-based awards using an approach in which the fair value of an award is estimated at the date of grant and recognized as an expense over the requisite service period. Compensation expense is adjusted for equity awards that do not vest because service or performance conditions are not satisfied. The three months ended March 31, 2009 and 2010 include $737,000 and $865,000 of additional compensation expense, respectively, as a result of stock based compensation.

     Weighted Average Shares Outstanding

     The consolidated financial statements include “basic” and “diluted” per share information. Basic per share information is calculated by dividing net income available to common stockholders by the weighted average number of shares outstanding. For the three months ended March 31, 2009 and 2010, net income (loss) was reduced by $750,000 of preferred dividend payments to arrive at net income (loss) available to common stockholders, respectively. Diluted per share information is calculated by also considering the impact of restricted common stock on the weighted average number of shares outstanding.

SUPERIOR WELL SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

     Although the restricted shares are considered legally issued and outstanding under the terms of the restricted stock agreement, they are still excluded from the computation of basic earnings per share. Once vested, the shares are included in basic earnings per share as of the vesting date. Superior includes unvested restricted stock with service conditions in the calculation of diluted earnings per share using the treasury stock method. Assumed proceeds under the treasury stock method would include unamortized compensation cost and potential windfall tax benefits. If dilutive, the stock is considered outstanding as of the grant date for diluted earnings per share computation purposes. If anti-dilutive, it would be excluded from the diluted earnings per share computation. The restricted shares were anti-dilutive for the three months ended March 31, 2009 and 2010, respectively.

     Additionally, we account for the effect of our Series A Preferred Stock (as defined in Note 3) in the diluted earnings per share calculation using the “if converted” method. Under this method, the $75 million of Series A Preferred Stock is assumed to be converted to common shares at the conversion price of $25.00, which equals three million “if converted” shares. The number of “if-converted” shares is weighted for the number of days outstanding in the period. If dilutive, these shares would be considered outstanding for the first three months of 2010 for diluted earnings per share computation purposes. If anti-dilutive, these shares would be excluded from the diluted earnings per share computation. These “if converted” shares were anti-dilutive for the three months ended March 31, 2009 and March 31, 2010.

     Reclassification

     Certain prior amounts have been reclassified to conform to the current year presentation. These reclassifications had no impact on operating income (loss) for any of the periods presented.

3. Business Combinations

     Assets acquired in business combinations were recorded on Superior’s consolidated balance sheets as of the date of the respective acquisition based upon their estimated fair values at such dates. The results of operations of businesses acquired by Superior have been included in Superior’s consolidated statements of income since their respective dates of acquisition. The excess of the purchase price over the estimated fair values of the underlying net assets acquired, including identifiable intangible assets was allocated to goodwill. When appropriate, we engage third-party appraisal firms to assist in fair value determination of equipment, identifiable intangible assets and any other significant assets or liabilities and the determination of the fair-value of non-cash consideration that may be issued to seller.

     In July 2008, Superior purchased substantially all the operating assets of Nuex Wireline, Inc. (“Nuex”) for approximately $6.0 million in cash and potential payments of up to $1.5 million over a three-year period pursuant to an earnout arrangement. Nuex provides cased hole completion services. The operating assets included five cased hole trucks and various tools and logging systems that are compatible with Superior’s existing systems. Superior retained all of Nuex’s 16 employees. The acquired operations were integrated into Superior’s Rocky Mountain operations, which expanded our presence in Brighton, Colorado. Nuex’s purchase cost was allocated as follows: $1.5 million, $3.6 million and $0.9 million to property, plant and equipment, goodwill and intangible assets, respectively.

     In November 2008, Superior purchased the pressure pumping, fluid logistics and completion, production and rental tools business lines from Diamondback for approximately $202.0 million. The acquisition consideration consisted of $71.5 million in cash, $42.9 million of Series A 4% Convertible Preferred Stock ($75 million liquidation preference) (the “Series A Preferred Stock”) with a perpetual term and $80 million in Second Lien Notes (as defined in Note 5) aggregating $194.4 million plus $7.6 million of transaction costs for a total purchase price of $202.0 million. The fair value of the Series A Preferred Stock was estimated using quotes obtained from an investment bank that used a convertible valuation tool used by investment banks, convertible investors and other market participants to value equity-linked securities. The Diamondback assets included 128,000 horsepower of technical pumping equipment operating in the Anadarko, Arkoma, and Permian Basins, as well as the Barnett Shale, Woodford Shale, West Texas, Southern Louisiana and Texas Gulf Coast. Additionally, the Diamondback assets included water transport equipment, frac tanks and six water disposal wells. Diamondback’s purchase cost was allocated as follows: $165.2 million, $12.4 million, $7.0 million and $22.3 million to property, plant and equipment,

SUPERIOR WELL SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

inventory, intangible assets and goodwill, respectively. Additionally, Superior assumed liabilities in connection with the Diamondback purchase of accrued paid time off, capital lease obligations, and asset retirement obligations of $1.0 million, $3.4 million and $0.4 million, respectively.

4. Property, Plant and Equipment

     Property, plant and equipment at December 31, 2009 and March 31, 2010 consisted of the following:

		December 31,				March 31,
		2009				2010
		(in thousands)
Property, Plant and Equipment:
Land		$	453			$	453
Building and improvements			19,647				19,917
Equipment and vehicles			540,050				544,830
Disposal wells and equipment			8,705				8,705
Construction in progress			9,305				8,739
			578,160				582,644
Accumulated depreciation			(168,608	)			(187,224	)
Total property, plant and equipment, net		$	409,552			$	395,420

5. Short and Long-term Obligations

     Debt

     On September 30, 2008, we entered into a credit agreement (as amended, the “Credit Agreement”) with a syndicate of financial institutions that provided for a secured revolving credit facility (our “Credit Facility”) which matures on March 31, 2013. As a result of several amendments to the Credit Agreement during 2009, amounts outstanding under our Credit Facility cannot exceed the lesser of the total capacity and the “borrowing base” (as defined in the Credit Agreement) that currently consists of (i) 80% of eligible accounts receivable and (ii) 20% of the net book value of property, plant and equipment. The total capacity under our Credit Facility is currently $100.0 million and was reduced to $75.0 million when we received our federal tax refund in April 2010. If the fluid logistics business is sold, the total capacity under our Credit Facility will be reduced to $50.0 million and the “borrowing base” will consist solely of 80% of eligible accounts receivable.

     Borrowings under our Credit Facility are secured by substantially all of our business assets. The interest rate on borrowings under our Credit Facility is set, at our option, at either LIBOR plus a spread of 4.0% or the prime lending rate plus a spread of 2.0%. At December 31, 2009, we had $82.7 million outstanding, $7.3 million in letters of credit outstanding and $10.0 million of available capacity under our credit facility. The weighted average interest rate for our Credit Facility was 3.6% during 2009. At March 31, 2010, we had $83.5 million outstanding, $6.4 million in letters of credit outstanding and $10.1 million of available capacity under our credit facility. The weighted average interest rate for our Credit Facility for the three months ended March 31, 2010 was 4.3%.

     In connection with the Diamondback asset acquisition (Note 3), Superior issued an aggregate principal amount of $80 million second lien notes due November 2013 (the “Second Lien Notes”). The Second Lien Notes are secured by a second priority lien on the assets secured by our Credit Facility. In connection with the issuance of the Second Lien Notes, we entered into an indenture (the “Indenture”), among us, our subsidiaries and the Wilmington Trust FSB, as trustee. Interest on the Second Lien Notes accrues at an initial rate of 7% per annum and the rate increases by 1% per annum on each anniversary date of the Indenture. Interest is payable quarterly in arrears on January 1, April 1, July 1 and October 1, commencing on January 1, 2009.

     Under the Credit Agreement and the Indenture, we are subject to certain limitations, including limitations on our ability to: make capital expenditures in excess of $6.0 million per quarter through March 2011; incur additional debt or sell assets; make certain investments, loans and acquisitions; guarantee debt; grant liens; enter into transactions with affiliates and engage in other lines of business. We are also subject to financial covenants, which include minimum quarterly EBITDA amounts, senior and total debt to EBITDA ratios and an interest coverage

SUPERIOR WELL SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

ratio. These covenants are subject to a number of exceptions and qualifications set forth in the Credit Agreement. At December 31, 2009 and March 31, 2010, we were in compliance with the financial covenants required under the Credit Agreement and the Indenture. Long-term debt at December 31, 2009 and March 31, 2010 consisted of the following (amounts in thousands):

		December 31,				March 31,
		2009				2010
Credit Facility with interest rates at either LIBOR plus a spread of 4.0% or the prime lending rate plus a spread of 2.0% due March 2013, collateralized by cash, investment property, accounts receivable, inventory, intangibles and equipment		$	82,689			$	83,544
Second Lien Notes due November 2013 with an initial interest rate of 7.0% per annum which increases 1% per annum on the anniversary date of the indenture, collateralized by a second priority lien on Superior’s assets secured by the Credit Facility			80,000				80,000
Mortgage notes payable to a bank with interest at the bank’s prime lending rate minus 1%, payable in monthly installments of $8,622 plus interest through January 2021, collateralized by real property			995				966
Notes payable to sellers with nominal interest rates due through December 2010, collateralized by specific buildings and equipment			36				23
			163,720				164,533
Less — Payments due within one year			126				126
Total		$	163,594			$	164,407

     Principal payments required under our long-term debt obligations during the next five years and thereafter are as follows: 2010-$126,000, 2011-$103,000, 2012-$103,000, 2013-$163,647,000, 2014-$103,000 and thereafter $451,000.

     Capital Lease Obligations

     In connection with the Diamondback asset acquisition (Note 3), Superior recorded capital leases on equipment that extend through 2011. Assets held under capital leases totaling $1.7 million net book value are included in property, plant and equipment within the equipment and vehicles asset class. Amortization of assets recorded under capital leases is reported in depreciation, amortization and accretion expense.

     Future minimum lease payments under capital leases as of March 31, 2010 are (amounts in thousands):

Due in 1 year		$	1,312
Due in 2 years			676
Total minimum payments			1,988
Less amounts representing interest			116
Total obligation under capital leases			1,872
Less current portion			1,238
Long-term portion		$	634

6. Stockholders’ equity

     Common Stock

     We are authorized to issue 70,000,000 shares of common stock, $0.01 par value per share, of which 30,688,137 and 30,835,234 shares of common stock were outstanding as of December 31, 2009 and March 31, 2010, respectively. All of our currently outstanding shares of common stock are listed on the NASDAQ Global Select Market under the symbol “SWSI”.

     Subject to the rights of the holders of any outstanding shares of preferred stock, each share of common stock is entitled to: (i) one vote on all matters presented to the stockholders, with no cumulative voting rights; (ii) receive such dividends as may be declared by our Board of Directors (the “Board”) out of funds legally available therefore; and (iii) in the event of our liquidation or dissolution, share ratably in any distribution of our assets.

SUPERIOR WELL SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

     In October 2009, Superior completed a follow-on offering of 6,900,000 shares of its common stock, which included 900,000 shares sold by Superior to cover the exercise by the underwriters of an option to purchase additional shares to cover over-allotments. Proceeds to Superior, net of the underwriting discount and offering expenses, were approximately $68.5 million.

     Preferred Stock

     We are authorized to issue 10,000,000 shares of preferred stock, $0.01 par value per share, of which 75,000 shares of preferred stock were outstanding both at December 31, 2009 and March 31, 2010. The preferred stock is issuable in series with such voting rights, if any, designations, powers, preferences and other rights and such qualifications, limitations and restrictions as may be determined by the Board. The Board may fix the number of shares constituting each series and increase or decrease the number of shares of any series.

     In November 2008, we issued 75,000 shares of Series A Preferred Stock in connection with the Diamondback asset acquisition. The Series A Preferred Stock is perpetual and ranks senior to our common stock with respect to payment of dividends, and amounts upon liquidation, dissolution or winding up. As of December 31, 2009 and March 31, 2010, 75,000 shares of a Series A Preferred Stock were outstanding.

     Dividends

     Holders of Series A Preferred Stock are entitled to receive, when, as and if declared by the Board out of our assets legally available therefore, cumulative cash dividends at the rate per annum of $40.00 per share of Series A Preferred Stock. Dividends on the Series A Preferred Stock are payable quarterly in arrears on December 1, March 1, June 1 and September 1 of each year (and, in the case of any undeclared and unpaid dividends, at such additional times and for such interim periods, if any, as determined by the Board), at such annual rate. Dividends are cumulative from the date of the original issuance of the Series A Preferred Stock, whether or not in any dividend period or periods we have assets legally available for the payment of such dividends.

     As of March 31, 2010, dividends on outstanding shares of Series A Preferred Stock have been declared and paid in full with respect to each quarter since initial issuance.

     Liquidation Preference

     Holders of Series A Preferred Stock are entitled to receive, in the event that we are liquidated, dissolved or wound up, whether voluntary or involuntary, $1,000 per share (the “Liquidation Value”) plus an amount per share equal to all dividends undeclared and unpaid thereon to the date of final distribution to such holders (the “Liquidation Preference”), and no more. Until the holders of Series A Preferred Stock have been paid the Liquidation Preference in full, no payment will be made to any holder of Junior Stock upon our liquidation, dissolution or winding up. The term “Junior Stock” means our common stock and any other class of our capital stock issued and outstanding that ranks junior as to the payment of dividends or amounts payable upon liquidation, dissolution and winding up to the Series A Preferred Stock. As of December 31, 2009 and March 31, 2010, the Series A Preferred Stock had a total Liquidation Preference of $75.0 million.

     Redemption

     The Series A Preferred Stock is redeemable at any time on or after November 18, 2013 and Superior, at its option, may redeem any or all at 101% of the Liquidation Value, plus, all accrued dividends with respect thereto to the redemption. The redemption price is payable in cash.

     Voting Rights

     Except as otherwise from time to time required by applicable law or upon certain events of preferred default, the holders of Series A Preferred Stock have no voting rights and their consent is not required for taking any corporate action. When and if the holders of the Series A Preferred Stock are entitled to vote, each holder will be entitled to one vote per share.

SUPERIOR WELL SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

     Conversion

     Each share of Series A Preferred Stock is convertible, in whole or in part at the option of the holders thereof, into shares of common stock at a conversion price of $25.00 per share of common stock (equivalent to a conversion rate of 40 shares of common stock for each share of Series A Preferred Stock), representing 3,000,000 common shares at December 31, 2009 and March 31, 2010. The right to convert shares of Series A Preferred Stock called for redemption will terminate at the close of business on the day preceding a redemption date.

     Stock Incentive Plan

     In July 2005, Superior adopted a stock incentive plan for its employees, directors and consultants. The 2005 Stock Incentive Plan (the “2005 Stock Incentive Plan”) permits the grant of non-qualified stock options, incentive stock options, stock appreciation rights, restricted stock awards, phantom stock awards, performance awards, bonus stock awards or any combination of the foregoing to employees, directors and consultants. A maximum of 2,700,000 shares of common stock may be issued pursuant to awards under the 2005 Stock Incentive Plan. The Compensation Committee of the Board, which is composed entirely of independent directors, determines all awards made pursuant to the 2005 Stock Incentive Plan. In March 2010, the 2005 Stock Incentive Plan was amended and restated (the “Amended and Restated Incentive Compensation Plan”) and subsequently approved by the stockholders at the Annual Meeting of Stockholders in May 2010.

     Superior accounts for equity awards using an approach in which the fair value of an award is estimated at the date of grant and recognized as an expense over the requisite service period. Compensation expense is adjusted for equity awards that do not vest because service or performance conditions are not satisfied.

     During 2007, Superior granted restricted common stock awards that totaled 135,200 shares. Superior’s non-employee directors, officers and key employees received restricted common stock awards during 2007 of 22,000, 26,000 and 87,200, respectively. During 2008, Superior granted restricted common stock awards that totaled 176,400 shares. Superior’s non-employee directors, officers and key employees received restricted common stock awards during 2008 of 12,000, 32,500 and 131,900, respectively. During 2009, Superior granted restricted common stock awards that totaled 195,750 shares. Superior’s non-employee directors, officers and key employees received restricted common stock awards during 2009 of 18,000, 33,500 and 144,250, respectively. During 2010, Superior granted restricted common stock awards that totaled 198,650 shares. Superior’s non-employee directors, officers and key employees received restricted common stock awards during 2010 of 18,000, 45,250 and 135,400, respectively. Each award is subject to a service requirement that requires the director, officer or key employee to continuously serve as a member of the Board or as an employee of Superior from the date of grant through the number of years following the date of grant as set forth in the following schedule. Under the terms of the Stock Incentive Plan, vested shares may be issued net of a number of shares necessary to satisfy the participant’s income tax obligation. Such amounts are recorded as shares retired. The forfeiture restrictions lapse with respect to a percentage of the aggregate number of restricted shares in accordance with the following schedule:

		Percentage of Total Number of Restricted
		Shares as to Which Forfeiture Restrictions
Number of Full Years		Lapse
Less than 1 year			0	%
1 year			15	%
2 years			30	%
3 years			45	%
4 years			60	%
5 years or more			100	%

     Under the 2005 Stock Incentive Plan, the fair value of the restricted stock awards is based on the closing market price of Superior’s common stock on the date of grant. A summary of the activity of Superior’s restricted stock awards are as follows:

SUPERIOR WELL SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

						Weighted Average
						Grant Date Fair
		Number of shares				Value Per Share
Nonvested at December 31, 2008			463,086			$	22.97
Granted			195,750				8.94
Vested			(73,570	)			24.88
Forfeited			(67,995	)			17.69
Retired			(9,216	)			25.51
Nonvested at December 31, 2009			508,055				17.95
Granted			198,650				17.87
Vested			(75,773	)			17.68
Forfeited			(35,993	)			14.37
Retired			(15,561	)			17.69
Nonvested at March 31, 2010			579,378			$	18.19

     The aggregate market value of cumulative awards was approximately $17.8 million, before the impact of income taxes. At March 31, 2010, Superior’s unrecognized compensation costs related to non-vested awards amounted to $7.8 million. Superior is recognizing the expense in connection with the restricted share awards ratably over the five year vesting period. Compensation expense related to the 2005 Stock Incentive Plan for the three months ended March 31, 2009 and 2010 was $737,000 and $865,000, respectively.

7. Income Taxes

     Superior accounts for income taxes and the related accounts under the liability method. Deferred taxes and assets are determined based on the difference between the financial statement and tax bases of assets and liabilities using enacted rates expected to be in effect during the year in which the basis differences reverse.

     The provision (benefit) for income taxes is comprised of:

		Three months ended March 31,
		2009				2010
Current:
State and local		$	(800	)		$	—
U.S. federal			(11,486	)			—
Total current			(12,286	)			—
Deferred:
State and local			115				(481	)
U.S. federal			4,419				(4,044	)
Total deferred			4,534				(4,525	)
Provision (benefit) for income tax expense		$	(7,752	)		$	(4,525	)

     Significant components of Superior’s deferred tax assets and liabilities are as follows:

		December 31,				March 31,
		2009				2010
		(amounts in thousands)
Deferred tax assets:
Restricted stock		$	1,464			$	657
Accrued expenses and other			1,330				1,244
Net operating loss carry forward			22,360				29,159
Allowance for doubtful accounts receivable			2,227				1,591
Total deferred tax assets			27,381				32,651
Deferred tax liabilities:
Depreciation differences on property, plant and equipment			(60,688	)			(61,433	)
Total deferred tax liabilities			(60,688	)			(61,433	)
Net deferred taxes		$	(33,307	)		$	(28,782	)

SUPERIOR WELL SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

     A reconciliation of income tax expense using the statutory U.S. income tax rate compared with actual income tax expense is as follows:

		Three months ended March 31,
		2009				2010
Federal statutory tax rate			(35.0	)%			(35.0	)%
Impact of vesting of restricted stock			3.0				4.0
State income taxes			(2.0	)			(2.0	)
Other			0.5				(1.0	)
Effective income tax rate			(34.5	)%			(34.0	)%

     We file U.S. federal tax returns and separate income tax returns in many state and local jurisdictions. We are subject to U.S. federal income tax examinations for years after 2005 and we are subject to various state and local tax examinations for years after 2005. Our continuing policy is to recognize interest related to income tax expense in interest expense and penalties in general and administrative expense. We do not have any accrued interest or penalties related to tax amounts as of March 31, 2009 and 2010. Throughout 2009, our unrecognized tax benefits were insignificant. We had available at March 31, 2010, a U.S. federal income tax net operating loss (“NOL”) carryforward of approximately $21.7 million which will expire between 2029 and 2030. Additionally, we have $7.4 million of state income tax NOL carryforward and $1.0 million of U.S. federal alternative minimum tax NOL carryforward available at March 31, 2010. The state NOL and U.S. federal alternative minimum tax carryforward periods range from 5 to 20 years.

8. 401(k) Plan

     Superior Well has a defined contribution profit sharing/401(k) retirement plan (“the Plan”) covering substantially all employees. Employees are eligible to participate after six months of service. Under terms of the Plan, employees are entitled to contribute up to 15% of their compensation, within limitations prescribed by the Internal Revenue Code. Superior Well may elect to make discretionary contributions to the Plan, all subject to vesting ratably over a three-year period.

9. Related-Party Transactions

     Superior Well provides technical pumping services and down-hole surveying services to a customer owned by certain stockholders and directors of Superior. The total amounts of services provided to this affiliated party for the three months ended March 31, 2009 and 2010 were approximately $751,000 and $855,000, respectively. The accounts receivable outstanding from the affiliated party were $846,000 and $460,000 at December 31, 2009 and March 31, 2010, respectively.

     Superior Well also regularly purchases, in the ordinary course of business, materials from vendors owned by certain stockholders and directors of Superior. The total amounts paid to these affiliated parties were approximately $734,000, and $451,000 for the three months ended March 31, 2009 and 2010, respectively. Superior Well had accounts payable to these affiliates of $331,000 and $784,000 at December 31, 2009 and March 31, 2010, respectively.

     At December 31, 2009 and March 31, 2010, a commercial bank in which certain stockholders and directors of Superior hold ownership interests held $995,000 and $966,000 of Superior Well’s mortgage notes (Note 5) and a $1.6 million participation in the Credit Facility (Note 5).

     In connection with the Diamondback asset acquisition (Note 3), Superior Well entered into a transition services agreement to provide temporary services to Diamondback, which terminated on June 30, 2009. These services included assistance in payroll, information technologies and certain other corporate support service matters. The total amount of services provided to Diamondback for the three months ended March 31, 2009 was approximately

SUPERIOR WELL SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

$102,000. There were no services provided or accounts receivable outstanding for the three months ending March 31, 2010.

     In connection with the Diamondback asset acquisition (Note 3), Superior Well entered into facility leases with an affiliate of Diamondback. The lease terms range from nine months to five years and the monthly lease payments are approximately $122,000. Rent expense for these leased facilities for the three month period ended March 31, 2009 and 2010 was $367,000 and $118,000, respectively. There was no unpaid balance at December 31, 2009 and March 31, 2010.

10. Business Segment Information

     Superior’s method of determining what information to report is based on the way our management organizes the operating segments for making operational decisions and assessing financial performance. We operate out of two subsidiaries that form the basis for the segments that we report. These segments have been selected based on resource allocation by management and performance. Following is a discussion of our reporting segments.

     Technical Services— These operating segments provide completion services, down-hole surveying services and technical pumping services (consisting of fracturing, cementing, acidizing, nitrogen, down-hole surveying and completion services). These operating segments have been aggregated into one reportable segment because they offer the same type of services, have similar economic characteristics, have similar production processes and use the same methods to provide services.

     Fluid Logistics— This operating segment provides a variety of services to assist our customers to obtain, transport, store and dispose of fluids that are involved in the drilling, development and production of hydrocarbons.

     We evaluate performance and allocate resources based on operating income (loss). Information regarding our two reportable operating segments, technical services and fluid logistics, is set forth below:

		Three Months Ended March 31, 2010
		Technical				Fluid
		Services				Logistics				Corporate				Total
						(in thousands)
Net revenue		$	118,347			$	4,993			$	—			$	123,340
Depreciation, amortization and accretion		$	18,262			$	1,397			$	128			$	19,787
Operating loss		$	(5,212	)		$	(1,207	)		$	(3,992	)		$	(10,411	)
Capital expenditures		$	5,419			$	—			$	11			$	5,430
Segment assets as of March 31, 2010		$	527,022			$	40,374			$	4,325			$	571,721

		Three Months Ended March 31, 2009
		Technical				Fluid
		Services				Logistics				Corporate				Total
						(in thousands)
Net revenue		$	113,260			$	9,021			$	—			$	122,281
Depreciation, amortization and accretion		$	15,919			$	1,433			$	133			$	17,485
Operating income (loss)		$	(13,033	)		$	(2,211	)		$	(3,850	)		$	(19,094	)
Capital expenditures		$	9,219			$	10			$	127			$	9,356
Segment assets as of March 31, 2009		$	585,344			$	56,035			$	10,783			$	652,162

SUPERIOR WELL SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

     We do not allocate interest expense, other expense or tax expense to the operating segments. The following table reconciles operating income (loss) as reported above to net income (loss) for the three months ended March 31, 2009 and 2010.

		Three Months Ended March 31,
		2009				2010
		(in thousands)
Segment operating income (loss)		$	(19,094	)		$	(10,411	)
Interest expense			3,176				2,902
Other income (expense), net			(193	)			136
Income taxes (benefit)			(7,752	)			(4,525	)
Net income (loss)		$	(14,711	)		$	(8,652	)

11. Commitments and Contingencies

     Minimum annual rental payments, principally for non-cancelable real estate and vehicle leases with terms in excess of one year, in effect at December 31, 2009, were as follows: 2010-$9,311,000; 2011-$7,098,000; 2012-$5,144,000; 2013-$3,211,000, and 2014-$1,148,000.

     Total rental expense charged to operations was approximately $2,477,000 and $2,110,000 for the three months ended March 31, 2009 and 2010, respectively.

     In January 2010, we amended a take-or-pay contract with Preferred Rocks USS, Inc. to purchase fracturing sand through December 2015. In connection with the take-or-pay contract, Superior advanced $15 million for materials that will be delivered in the future. Under the amended terms of the take-or-pay contract, Superior earns a 6% interest rate on the unused portion of the advance on materials. The advance on materials for future delivery will be used to offset future purchase commitments under the take-or-pay contract. Effective January 1, 2010, the minimum purchases under the take-or-pay contract are estimated at $14.2 million annually.

     Superior had commitments of approximately $1.7 million and $4.8 million for capital expenditures as of December 31, 2009 and March 31, 2010, respectively.

     Superior is involved in various legal actions and claims arising in the ordinary course of business. Management is of the opinion that the outcome of these lawsuits will not have a material adverse effect on the financial position, results of the operations or cash flow of Superior.

12. Fair Value of Financial Instruments

     The fair values are classified according to a hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. This hierarchy consists of three broad levels. Level 1 inputs on the hierarchy consist of unadjusted quoted prices in active markets for identical assets and liabilities and have the highest priority. Level 2 inputs consist of quoted prices in active markets for similar assets and liabilities and inputs that are observable for the asset or liability. Level 3 inputs have the lowest priority. Superior uses appropriate valuation techniques based on the available inputs to measure the fair values of its assets and liabilities. When available, Superior measures fair value using Level 1 inputs because they generally provide the most reliable evidence of fair value.

     Superior’s financial instruments consist primarily of cash and cash equivalents, accounts receivable, accounts payable, notes payable and long term debt. The carrying amount of cash and cash equivalents, accounts receivable and accounts payable approximate their fair value due to the short-term nature of such instruments. The carrying value of our Credit Facility and mortgage notes payable approximates fair value at December 31, 2009 and March 31, 2010, since the interest rates are market-based and are generally adjusted periodically, representing Level 1 measurements.

     The Second Lien Notes are not actively traded in an established market. The fair values of this debt is estimated by using Standard & Poor’s leveraged loan composite indices with similar terms and maturity, that is, a

SUPERIOR WELL SERVICES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

     Level 2 fair value measurement. The fair value of the Second Lien Notes was $76.8 million compared to a carrying value of $80.0 million at March 31, 2010.

13. Guarantees of Securities Registered

     Superior filed a registration statement on Form S-3 that included $80 million of outstanding debt securities that were issued on November 18, 2008 and that are guaranteed by all of Superior’s subsidiaries. Superior, as the parent company, has no independent operating assets or operations. The subsidiaries’ guarantees of the debt securities are full and unconditional as well as joint and several. In addition, there are no restrictions on the ability of Superior to obtain funds from its subsidiaries by dividend or loan, and there are no restricted assets in any subsidiaries although all business assets secure debt.

14. Subsequent Events

     On April 8, 2010 we received a $34.6 million federal income tax refund that we used to repay a portion of the borrowings under our Credit Facility. Under the terms of the Credit Facility, the receipt of the federal income tax refund reduced the Credit Facility’s total capacity by $25.0 million to $75.0 million on April 8, 2010.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

     The following discussion and analysis should be read in conjunction with the consolidated financial statements and notes thereto included elsewhere in this report. This discussion contains forward-looking statements that reflect management’s current views with respect to future events and financial performance. Our actual results may differ materially form those anticipated in these forward-looking statements or as a result of certain factors such as those set forth below under “Cautionary Statement Regarding Forward-Looking Statements.”

Cautionary Statement Regarding Forward-Looking Statements

     This report contains certain “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Statements included in this report that are not historical facts, that address activities, events or developments that we expect or anticipate will or may occur in the future, including things such as plans for growth of the business, future capital expenditures, competitive strengths, goals, references to future goals or intentions or other such references are forward-looking statements. These statements can be identified by the use of forward-looking terminology, including “may,” “believe,” “expect,” “anticipate,” “estimate,” “continue,” or similar words. These statements are made by us based on our past experience and our perception of historical trends, current conditions and expected future developments as well as other considerations we believe are appropriate under the circumstances. Whether actual results and developments in the future will conform to our expectations is subject to numerous risks and uncertainties, many of which are beyond our control. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in these statements. Any differences could be caused by a number of factors, including, but not limited to:

	•		A sustained or continued decrease in domestic spending by the oil and natural gas exploration and production industry;
	•		a continued decline in or substantial volatility of crude oil and natural gas commodity prices;
	•		current weaknesses in the credit and capital markets and lack of credit availability;
	•		our inability to comply with the financial and other covenants in our debt agreements as a result of reduced revenues and financial performance or our inability to raise sufficient funds through assets sales or equity issuances;
	•		overcapacity and competition in our industry;
	•		unanticipated costs, delays and other difficulties in executing our long-term growth strategy;
	•		the loss of one or more significant customers;
	•		the loss of or interruption in operations of one or more key suppliers;
	•		the incurrence of significant costs and liabilities in the future resulting from our failure to comply with new or existing environmental regulations or an accidental release of hazardous substances into the environment; and
	•		other financial, operational and legal risks and uncertainties detailed from time to time in our Securities and Exchange Commission (“SEC”) filings.

     When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements set forth in our Annual Report on Form 10-K for the year ended December 31, 2009, as well as other written and oral statements made or incorporated by reference from time to time by us in other reports and filings with the SEC. All forward-looking statements included in this report and all subsequent written or oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these cautionary statements. The forward-looking statements speak only as of the date made, other than as required by

law, and we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

Overview

     We are a Delaware corporation formed in 2005 to serve as the parent holding company for an oilfield services business operating under the Superior Well Services name since 1997. We service our customers in key markets in many of the active domestic oil and natural gas producing regions in the Appalachian, Mid-Continent, Rocky Mountain, Southwest and Southeast regions of the United States. In August 2005, we completed our initial public offering of 6,460,000 shares of common stock at a price of $13.00 per share and follow-on offerings of common stock in December 2006 for 3,690,000 shares at a price of $25.50 per share and in October 2009 for 6,900,000 shares at a price of $10.50 per share. We provide a wide range of wellsite solutions to oil and natural gas companies, primarily technical pumping services and down-hole surveying services. We focus on offering technologically advanced equipment and services at competitive prices, which we believe allows us to successfully compete against both major oilfield services companies and smaller, independent service providers.

     In November 2008, we purchased the pressure pumping, fluid logistics and completion, production and rental tools business lines from Diamondback Energy Holdings, LLC, or Diamondback, for approximately $202.0 million. The acquisition consideration consisted of $71.5 million in cash, $42.9 million of our Series A 4% Convertible Preferred Stock ($75 million liquidation preference), or the Series A Preferred Stock, and $80 million in second lien notes aggregating $194.4 million plus $7.6 million of transaction costs for a total purchase price of $202.0 million. See Note 3 to our consolidated financial statements for more information. As part of the acquisition, we acquired 128,000 horsepower, 105 transports and trucks, 400 frac tanks, six water disposal wells and completion and rental tool businesses in Louisiana, Texas and Oklahoma. The assets that we purchased from Diamondback are operating in the Anadarko, Arkoma, and Permian Basins, as well as the Barnett Shale, Woodford Shale, West Texas, southern Louisiana and the Texas Gulf Coast.

Services Offered

     Our services are conducted through two principal business segments, which are technical services and fluid logistics services. Each business segment includes service lines that contain similarities among customers, financial performance and management, as well as the economic and business conditions impacting their activity levels. Technical services include technical pumping services, completion, production and rental tool services and down-hole surveying services. Fluid logistics services include those services related to the transportation, storage and disposal of fluids that are used in the drilling, development and production of hydrocarbons. Substantially all of our customers are domestic oil and natural gas exploration and production companies that typically require all types of services in their operations. Our operating revenue from these operations, and their relative percentages of our total revenue, consisted of the following (dollars in thousands):

		Three Months Ended March 31,
		2009								2010
Revenue:
Technical pumping services		$	113,274				92.6	%		$	118,347				96.0	%
Fluid Logistics			9,007				7.4				4,993				4.0
Total revenue		$	122,281				100.0	%		$	123,340				100.0	%

     The following is a brief description of our services:

     Technical Services

     Technical Pumping Services

     We offer three types of technical pumping services — stimulation, nitrogen and cementing — which accounted for 75.2%, 3.6% and 10.4% of our revenue for the three months ended March 31, 2010 and 65.0%, 5.7% and 13.6% of our revenue for the three months ended March 31, 2009, respectively. Our fluid-based stimulation services include fracturing and acidizing, which are designed to improve the flow of oil and natural gas from producing

zones. In addition to our fluid-based stimulation services, we also use nitrogen to stimulate wellbores. Our foam-based nitrogen stimulation services accounted for substantially all of our total nitrogen services revenue for the three months ended March 31, 2009 and 2010. Our cementing services consist of blending high-grade cement and water with various additives to create a cement slurry that is pumped through the well casing into the void between the casing and the bore hole. Once the slurry hardens, the cement isolates fluids and gases, which protects the casing from corrosion, holds the well casing in place and controls the well.

     Completion, Production and Rental Tool Services

     Completion and production services were added in connection with the Diamondback asset acquisition and accounted for 2.1% and 3.1% of our revenues for the three months ended March 31, 2010 and 2009, respectively. Our completion and production services and other production related activities include specialty services, many of which are performed after drilling has been completed. Consequently, these services occur later in the lifecycle while a well is being completed or during the production stage. These specialty services include plugging and abandonment, gravel pack, storm valves, roustabout services, as well as the sale and rental of equipment. As newly drilled oil and natural gas wells are prepared for production, our completion services include selectively testing producing zones of the wells before and after stimulation.

     Down-Hole Surveying Services

     We offer two types of down-hole surveying services — logging and perforating — which collectively accounted for approximately 4.7% and 5.2% of our revenue for the three months ended March 31, 2010 and 2009, respectively. Our logging services involve the gathering of down-hole information through the use of specialized tools that are lowered into a wellbore from a truck. An armored electro-mechanical cable, or wireline, is used to transmit data to our surface computer that records various characteristics about the formation or zone to be produced. We provide perforating services as the initial step of stimulation by lowering specialized tools and perforating guns into a wellbore by wireline. The specialized tools transmit data to our surface computer to verify the integrity of the cement and position the perforating gun, which fires shaped explosive charges to penetrate the producing zone to create a short path between the oil or natural gas reservoir and the production tubing to enable the production of hydrocarbons. We also perform workover services aimed at improving the production rate of existing oil and natural gas wells, including perforating new hydrocarbon bearing zones in a well once a deeper zone or formation has been depleted.

     Fluid Logistics Services

     Oil and natural gas operations use and produce significant quantities of fluids. We provide a variety of services to assist our customers to obtain, transport, store and dispose of fluids that are involved in the drilling, development and production of hydrocarbons. We own or lease over 100 fluid hauling transports and trucks, which are used to transport various fluids in the lifecycle of an oil or natural gas well. As of March 31, 2010, we also owned approximately 400 frac tanks that we rent to producers for use in fracturing and stimulation operations plus other fluid storage needs. We use our fleet of fluid hauling trucks to fill and empty the frac tanks and we deliver and remove these tanks from the well sites. As of March 31, 2010, we owned and operated six water disposal wells in North Texas and southern Oklahoma. The disposal wells are an important component of our fluid logistics operations as they provide an efficient solution for the disposal of waste waters. Our fluid logistics services accounted for approximately 4.0% and 7.4% of our revenues for the three months ended March 31, 2010 and 2009, respectively.

How We Generate Our Revenue

     The majority of our customers are regional, independent oil and natural gas companies. The primary factor influencing demand for our services by those customers is their level of drilling activity, which, in turn, depends primarily on current and anticipated future crude oil and natural gas commodity prices and production depletion rates.

     We generate revenue from our technical pumping services, completion, production and rental tool services and down-hole surveying services by charging our customers a set-up charge plus an hourly rate based on the type of equipment used. The set-up charges and hourly rates are determined by a competitive bid process and depend upon

the type of service to be performed, the equipment and personnel required for the particular job and the market conditions in the region in which the service is performed. Each job is given a base time allotment of six hours. We generally charge an increased hourly rate for each hour worked beyond the initial four hour base time allotment. We also charge customers for the materials, such as stimulation fluids, cement and nitrogen, that we use in each job. Material charges include the cost of the materials plus a markup and are based on the actual quantity of materials used.

     We generate revenue from our fluid logistics services by charging our customers based on volumes of fluids transported and disposed of and rental charges for use of our frac tanks. The rates for the transportation of fluids are generally determined by a competitive bid process and depend upon the type of service to be performed, the equipment and personnel and the cost of goods required for the particular job and the market conditions in the region in which the service is performed. The rates for our fluid disposal services vary depending on the type of fluid being disposed of, and the rates charged are generally driven by market conditions in the region the disposal well is located. Frac tanks are rented on a daily basis and the rates are generally driven by market conditions in the region the disposal well is located.

How We Evaluate Our Operations

     Our management uses a variety of financial and operational measurements to analyze the performance of our services. These measurements include the following: (1) operating income per operating region; (2) material and labor expenses as a percentage of revenue; (3) selling, general and administrative expenses as a percentage of revenue; and (4) Adjusted EBITDA, which is a non-GAAP financial measure and is discussed in more detail below.

     Operating Income per Operating Region

     We currently service customers in five operating regions through our 28 service centers. In April 2009, we ceased operations at our service centers in Wooster, Ohio and Cleveland, Oklahoma due to significant activity declines in those areas. In October 2009, we ceased operations at our service centers in Coalgate Oklahoma; Trinidad, Colorado; Alvarado, Texas and Artesia, New Mexico and ceased stimulation operations in Clinton, OK due to significant activity declines in those areas. In January 2010 we ceased operations at our service center in Farmington, New Mexico due to significant activity declines in that area. Our Appalachian region service centers are located in Bradford, Black Lick and Mercer, Pennsylvania; Kimball, Buckhannon and Jane Lew, West Virginia; Norton, Virginia; and Gaylord, Michigan. Our Southeast region service centers are located in Cottondale, Alabama; Columbia, Mississippi; and Bossier City and Broussard, Louisiana. Our Mid-Continent region service centers are located in Hominy, Clinton, Marlow, Countyline, Sweetwater, and Elk City, Oklahoma; Hays, Kansas; and Van Buren, Arkansas. Our Rocky Mountain region service centers are located in Vernal, Utah; Rock Springs, Wyoming; Williston, North Dakota; and Brighton, Colorado. Our Southwest region service centers are located in Cresson, Tolar, Midland and Victoria, Texas.

     The operating income (loss) generated in each of our operating regions is an important part of our operational analysis. We monitor operating income (loss) separately for each of our operating regions and analyze trends to determine our relative performance in each region. Our analysis enables us to more efficiently allocate our equipment and field personnel among our various operating regions and determine if we need to increase our marketing efforts in a particular region. By comparing our operating income (loss) on an operating region basis, we can quickly identify market increases or decreases in the diverse geographic areas in which we operate. It has been our experience that when we establish a new service center in a particular operating region, it may take from 12 to 24 months before that service center has a positive impact on the operating income (loss) that we generate in the relevant region.

     Material and Labor Expenses as a Percentage of Revenue

     A significant portion of the cost of revenues is comprised of the cost of materials, maintenance, fuel and the wages of our field personnel. Although, the cost of these expenses as a percentage of revenue has historically remained relatively stable for our established service centers, the industry experienced an unprecedented decline in drilling activity during 2009 compared to 2008. This rapid and deep reduction in drilling activity has resulted in heavy pricing pressure and severe margin contraction in all our service offerings. Beginning in the fourth quarter of 2009 and continuing through the first quarter of 2010, rig count and drilling activity started increasing in many

regions in the United States. The activity increases have been strongest in the more service-intensive shale plays, as well as the more oil-focused producing regions. Starting in the first quarter of 2010, we began to see modest pricing improvements from our customers on most of our services, which favorably impacted our operating margins during the first quarter of 2010. Recently, however, higher natural gas storage levels have weakened natural gas prices, which could negatively impact drilling activity for the remainder of 2010.

     Our material costs primarily include the cost of inventory consumed while performing our stimulation, nitrogen and cementing services. We try to pass on to our customers the increases in our material and fuel costs. However, due to the timing of our marketing and bidding cycles, there is generally a delay of several weeks or months from the time that we incur an actual price increase until the time that we can pass on that increase to our customers. In the current competitive environment, it is very difficult to pass on cost increases to our customers.

     Our labor costs consist primarily of wages for our field personnel. If we experience a shortage of qualified supervision personnel and equipment operators in certain areas in which we operate, it is possible that we will have to raise wage rates to attract and train workers from other fields in order to maintain or expand our current work force. We try to pass on higher wage expenses through an increase in our service rates. In the current competitive environment, it is very difficult to pass on these increases to our customers.

     Selling, General and Administrative Expenses as a Percentage of Revenue

     Our selling, general and administrative expenses, or SG&A expenses, include administrative, marketing and maintenance employee compensation and related benefits, office and lease expenses, insurance costs and professional fees, as well as other costs and expenses not directly related to field operations. Our management continually evaluates the level of our SG&A expenses in relation to our revenue because these expenses have a direct impact on our profitability.

     Adjusted EBITDA

     We define Adjusted EBITDA as net income (loss) before interest expense, income tax expense, non-cash stock compensation expense, non-cash goodwill and intangible impairment, depreciation, amortization and accretion expense. We believe Adjusted EBITDA is useful to investors in evaluating our operating performance because:

	•		it is widely used by investors in our industry to measure a company’s operating performance without regard to items such as interest expense, depreciation and amortization, which can vary substantially from company to company depending upon accounting methods and book value of assets, capital structure and the method by which the assets were acquired; and
	•		it helps investors more meaningfully evaluate and compare the results of our operations from period to period by removing the impact of our capital structure and asset base from our operating results.
			Our management uses Adjusted EBITDA:

	•		as a measure of operating performance because it assists us in comparing our performance on a consistent basis, since it removes the impact of our capital structure and asset base from our operating results;
	•		as a measure for planning and forecasting overall expectations and for evaluating actual results against such expectations;
	•		to assess compliance with financial ratios and covenants included in our credit facility;
	•		in communications with lenders concerning our financial performance; and
	•		to evaluate the viability of potential acquisitions and overall rates of return.

     Adjusted EBITDA is not a measure of financial performance under GAAP and should not be considered in isolation or as an alternative to cash flow from operating activities or as an alternative to net income (loss) as indicators of operating performance or any other measures of performance derived in accordance with GAAP. Other

companies in our industry may calculate Adjusted EBITDA differently than we do and Adjusted EBITDA may not be comparable with similarly titled measures reported by other companies. See “—Non-GAAP Accounting Measures” for a reconciliation of Adjusted EBITDA to net income (loss).

How We Manage Our Operations

     Our management team uses a variety of tools to manage our operations. These tools include monitoring: (1) service crew utilization and performance; (2) equipment maintenance performance; (3) customer satisfaction; and (4) safety performance.

     Service Crew Performance

     We monitor our revenue on a per service crew basis to determine the relative performance of each of our crews. We also measure our activity levels by the total number of jobs completed by each of our crews as well as by each of the trucks in our fleet. We evaluate our crew and fleet utilization levels on a monthly basis. By monitoring the relative performance of each of our service crews, we can more efficiently allocate our personnel and equipment to maximize our overall crew utilization.

     Equipment Maintenance Performance

     Preventative maintenance on our equipment is an important factor in our profitability. If our equipment is not maintained properly, our repair costs may increase and, during levels of high activity, our ability to operate efficiently could be significantly diminished due to having trucks and other equipment out of service. Our maintenance crews perform monthly inspections and preventative maintenance on each of our trucks and other mechanical equipment. Our management monitors the performance of our maintenance crews at each of our service centers by monitoring the level of maintenance expenses as a percentage of revenue. A rising level of maintenance expenses as a percentage of revenue at a particular service center can be an early indication that our preventative maintenance schedule is not being followed. In this situation, management can take corrective measures, such as adding additional maintenance personnel to a particular service center to help reduce maintenance expenses as well as ensure that maintenance issues do not interfere with operations.

     Customer Satisfaction

     Upon completion of each job, we encourage our customers to complete a ''pride in performance survey’’ that gauges their satisfaction level. The customer evaluates the performance of our service crew under various criteria and comments on their overall satisfaction level. Survey results give our management valuable information from which to identify performance issues and trends. Our management also uses the results of these surveys to evaluate our position relative to our competitors in the various markets in which we operate.

     Safety Performance

     Maintaining a strong safety record is a critical component of our operational success. Many of our larger customers have safety history standards we must satisfy before we can perform services for them. We maintain an online safety database that our customers can access to review our historical safety record. Our management also uses this safety database to identify negative trends in operational incidents so that appropriate measures can be taken to maintain a positive safety history.

Our Industry and Business Outlook

     We provide products and services primarily to domestic onshore oil and natural gas exploration and production companies for use in the drilling and production of oil and natural gas. The main factor influencing demand for well services in our industry is the level of drilling activity by oil and natural gas companies, which, in turn, depends largely on current and anticipated future crude oil and natural gas prices and production depletion rates. Our customers’ cash flows, in many instances, depend upon the revenue they generate from the sale of oil and natural gas. Lower oil and natural gas prices usually translate into lower exploration and production budgets. The opposite is true for higher oil and natural gas prices.

     Since the last half of 2008, the weakened credit markets and recessionary environment has reduced the demand for crude oil and natural gas. As a result, crude oil and natural gas prices fell sharply during the first half of 2009, which caused a decline in the demand for our services as customers reduced their exploration and production expenditures. The price of crude oil and natural gas has improved from pricing levels experienced during the first half of 2009, and this improvement has begun to be reflected in increased drilling activity. Beginning in the fourth quarter of 2009 and continuing through the first quarter of 2010, rig count and drilling activity started increasing in many regions of the United States. The activity increases have been strongest in the more service-intensive shale plays, as well as the more oil-focused producing regions. Due to improving equipment utilization, we began to see modest pricing improvements on most of our services during the first quarter of 2010. However, we believe pricing pressures are likely to continue until drilling activity materially increases and the current imbalance of excess capacity is reabsorbed. As a result, we intend to continue to focus on labor cost efficiencies and monitor discretionary spending to respond to prevailing levels of activity. We believe our ability to service more technically complex plays, our participation in many of the most active drilling plays in the United States, as well as our strength in the Appalachian region will generally help us to maintain a strong competitive position.

     Recently, higher natural gas storage levels have weakened commodity prices for natural gas, which could negatively impact drilling activity for the remainder of 2010. As of May 4, 2010 the 12-month strip for crude oil (West Texas Intermediate) and natural gas (Henry Hub) were $88.57 and $4.84, respectively. A sustained drop in the commodity prices for natural gas, coupled with tighter credit markets, may cause many exploration and production companies to reduce their capital spending. This would result in reduced demand for our services that could intensify the pricing pressures for our services. We continue to believe in the long term fundamentals of our business and the industry. However, the weakened economic and credit markets and the current high storage levels of natural gas have caused the short and mid-term outlook for our business and the industry to remain uncertain. Long-term forecast for energy demand suggests an increasing demand for oil and natural gas which, when coupled with flat or declining production curves, we believe should result over the long-term in the continuation of historically high crude oil and natural gas commodity prices.

     Some of the more significant indicators of current and future spending levels of oil and natural gas companies are crude oil and natural gas prices and the availability of credit, which together drive drilling activity. Our financial performance is significantly affected by crude oil and natural gas prices and domestic land rig activity, which are summarized in the following tables.

		Three Months Ended March 31,
		2009				2010				% Change
Average rig count (1)
Crude Oil			279				416				49.1	%
Natural gas			1,053				814				(22.7	)%
Total U.S. land rigs			1,332				1,230				(7.7	)%
Commodity prices (avg.):
Crude Oil (West Texas Intermediate) ($/ bbl)		$	43.08			$	78.72				82.7	%
Natural gas (Henry Hub) ($/mcf)			4.56				5.18				13.6	%

Our Long-term Growth Strategy

     Given the current market conditions it is unlikely that we will make significant growth investments in the near term. However, our long-term growth strategy contemplates engaging in organic expansion opportunities and, to a lesser extent, complementary acquisitions of other oilfield services businesses. Our organic expansion activities generally consist of establishing service centers in new locations, including purchasing related equipment and hiring experienced local personnel. Historically, many of our customers have asked us to expand our operations into new regions that they enter. Once we establish a new service center, we seek to expand our operations by attracting new customers and hiring additional local personnel.

     Our revenues from each operating region, and their relative percentage of our total revenue, consisted of the following (dollars in thousands):

		Three Months Ended March 31,
		2009								2010
Region		Revenue				Percent of Revenue				Revenue				Percent of Revenue
Appalachian		$	30,574				25.0	%		$	29,987				24.3	%
Southeast			21,403				17.5				22,387				18.1
Southwest			36,312				29.7				30,459				24.7
Mid-Continent			25,974				21.2				23,773				19.3
Rocky Mountain			8,018				6.6				16,734				13.6
Total		$	122,281				100.0	%		$	123,340				100.0	%

     We also pursue selected acquisitions of complementary businesses, such as our acquisition of the Diamondback assets, both in existing operating regions and in new geographic areas in which we do not currently operate. In analyzing a particular acquisition, we consider the operational, financial and strategic benefits of the transaction. Our analysis includes the location of the business, strategic fit of the business in relation to our business strategy, expertise required to manage the business, capital required to integrate and maintain the business, the strength of the customer relationships associated with the business and the competitive environment of the area where the business is located. From a financial perspective, we analyze the rate of return the business will generate under various scenarios, the comparative market parameters applicable to the business and the cash flow capabilities of the business.

     To successfully execute our long-term growth strategy, we will require access to capital on competitive terms to the extent that we do not generate sufficient cash from operations. We intend to finance future acquisitions primarily by using capacity available under our credit facility and equity or debt offerings or a combination of both. For a more detailed discussion of our capital resources, please read “ — Liquidity and Capital Resources.”

Our Results of Operations

     Our results of operations are derived primarily by three interrelated variables: (1) market price for the services we provide; (2) drilling activities of our customers; and (3) cost of materials and labor. To a large extent, the pricing environment for our services will dictate our level of profitability. Our pricing is also dependent upon the prices and market demand for crude oil and natural gas, which affect the level of demand for, and the pricing of, our services and fluctuates with changes in market and economic condition and other factors. During 2009, increased capacity in each of our operating regions has resulted in significant downward pricing pressure and increased discounts in our service prices. Beginning in the first quarter of 2010, we started to see a small drop in discounts in our service prices that were more prevalent in higher activity markets. We expect that pricing pressure will continue in all our regions until the level of activity increases to absorb the excess capacity. To a lesser extent, seasonality can affect our operations in the Appalachian region and certain parts of the Mid-Continent and Rocky Mountain regions, which may be subject to a brief period of diminished activity during spring thaw due to road restrictions. As our operations have expanded in recent years into new operating regions in warmer climates, this brief period of diminished activity has a lesser impact on our overall results of operations.

     Results for the three months ended March 31, 2009 and 2010

     Our results of operations from our primary categories of services consisted of the following for the three month periods ended March 31, 2009 and 2010:

		Three months ended March 31,
		2009				2010
Statement of Operations Data
Revenue:
Technical pumping services		$	103,075			$	109,975
Down-hole surveying services			6,402				5,798
Completion services			3,797				2,574
Total Technical Services			113,274				118,347
Fluid logistics			9,007				4,993
Total revenue			122,281				123,340
Expenses:
Cost of revenue			125,320				122,095
Selling, general and administrative			16,055				11,656
Total expenses			141,375				133,751
Operating income (loss)		$	(19,094	)		$	(10,411	)

     Revenue

     The following table summarizes the dollar and percentage changes for the types of service revenues for the three month period ended March 31, 2009 when compared to the same period in 2010 (dollars in thousands):

		Three months ended March 31,
Revenues by service type		2009				2010				$ Change				% Change
Stimulation		$	79,505			$	92,793			$	13,288				16.7	%
Cementing			16,595				12,743				(3,852	)			(23.2	)
Nitrogen			6,975				4,439				(2,536	)			(36.4	)
Technical pumping services			103,075				109,975				6,900				6.7
Down-hole surveying services			6,402				5,798				(604	)			(9.4	)
Completion services			3,797				2,574				(1,223	)			(32.2	)
Total Technical Services			113,274				118,347				5,073				4.5
Fluid logistics			9,007				4,993				(4,014	)			(44.6	)
Total revenue		$	122,281			$	123,340			$	1,059				0.9	%

     The following table summarizes the dollar and percentage change in our revenues from each operating region for the three months ended March 31, 2009 when compared to the same period in 2010 (dollars in thousands):

		Three months ended March 31,
Region		2009				2010				$ Change				% Change
Appalachian		$	30,574			$	29,987			$	(587	)			(1.9	)%
Southeast			21,403				22,387				984				4.6
Southwest			36,312				30,459				(5,853	)			(16.1	)
Rocky Mountain			8,018				16,734				8,716				108.7
Mid-Continent			25,974				23,773				(2,201	)			(8.5	)
Total		$	122,281			$	123,340			$	1,059				0.9	%

     Revenues reached $123.3 million for the first quarter of 2010, which was a 0.9% increase compared to the same period last year. The year-over-year revenue growth in technical services was partially offset by declines in our fluid logistics services segment. The revenue growth in technical services revenue was driven by higher stimulation activity in the first quarter of 2010 compared to the first quarter of 2009. Activity declines in the Barnett shale, and to a lesser extent our Mid-Continent region, lowered fluid logistics services revenues by $4.0 million during the first quarter of 2010 compared to the first quarter of 2009. As a percentage of gross revenue, sales discounts increased 12.2% in the first quarter of 2010 compared to the first quarter of 2009 due to increased capacity and increased competition in certain of our operating regions which resulted in significant downward pressure on our service prices. As a result, we experienced pricing erosion in all of our service offerings during the first quarter of 2010 compared to the first quarter of 2009. All of our operating regions experienced higher sales discounts for the first quarter of 2010 compared to the first quarter of 2009. Our stimulation, nitrogen and cementing services continue to see the greatest downward pricing pressure.

     Cost of Revenue

     Cost of revenue decreased 2.6% or $3.2 million for the first quarter of 2010 compared to the first quarter of 2009. As a percentage of net revenue, cost of revenue decreased from 102.5% for the first quarter of 2009 to 99.0% for the first quarter of 2010 due primarily to lower labor costs that were partially offset by higher fuel, depreciation and repair and maintenance expenses. Labor expenses as a percentage of revenues decreased 7.6% to 20.0% in the first quarter of 2010 compared to the first quarter of 2009 due to improved utilization driven by headcount reductions we made in connection with our cost reduction efforts. As a percentage of net revenue, fuel costs, depreciation and repairs and maintenance expenses increased in the first quarter of 2010 compared to the first quarter of 2009 by 1.9%, 2.0%, and 0.9%, respectively. Fuel expense increases were caused by higher diesel fuel costs. Depreciation expense increased due to additional assets being utilized in the first quarter of 2010 compared to the first quarter of 2009. Higher stimulation activity levels in the more fracture intensive shale plays caused the increases in our repair and maintenance costs. Additionally, the higher level of sales discounts during the first quarter of 2010 compared to the first quarter of 2009 impacts the comparability of the year-over-year increases for materials, labor and depreciation.

     Selling, General and Administrative Expenses (SG&A)

     SG&A expenses decreased 27.4% or $4.4 million for the first quarter of 2010 compared to the first quarter of 2009. As a percentage of revenue, SG&A expenses decreased by 3.6% to 9.5% for the first quarter of 2010 from 13.1% for the first quarter of 2009. Driving the decline in SG&A expenses was a $4.1 million drop in labor costs due to headcount reductions made in connection with our cost cutting efforts. As a percentage of revenue, the portion of labor expenses included in SG&A expenses decreased 3.4% to 5.2% in the first quarter of 2010 compared to the first quarter of 2009. Additionally, the higher level of sales discounts during the first quarter of 2010 compared to the first quarter of 2009 impacts the comparability of the year-over-year increases for labor.

     Operating Income Loss and Adjusted EBITDA

     Operating loss was $10.4 million for the first quarter of 2010 compared to an operating loss of $19.1 million for the first quarter of 2009. As a percentage of revenue, operating loss was (8.4%) in the first quarter of 2010 as compared to (15.6%) in the first quarter of 2009. Adjusted EBITDA increased by $11.4 million in the first quarter of 2010 compared to the first quarter of 2009 to $10.4 million. For a definition of Adjusted EBITDA and a discussion of Adjusted EBITDA as a performance measure please see “How We Evaluate Our Operations — Adjusted EBITDA.” For a reconciliation of Adjusted EBITDA to net income, please see “Non-GAAP Accounting Measures.” Net loss decreased from $14.7 million in the first quarter of 2009 to $8.7 million in the first quarter of 2010 due to the labor cost reductions and stimulation activity level increases described above.

Liquidity and Capital Resources

     General

     We rely on cash generated from operations, public and private offerings of debt and equity securities and borrowings under our credit facility to satisfy our liquidity needs. Our ability to fund operating cash flow shortfalls, fund planned capital expenditures and make acquisitions will depend upon our future operating performance, and more broadly, on the availability of equity and debt financing, which will be affected by prevailing economic conditions in our industry and financial, business and other factors, some of which are beyond our control. At March 31, 2010, we had $10.1 million of availability under our credit facility that can be used for working capital purposes and planned capital expenditures. Our ability to fund our operations and planned 2010 capital expenditures will depend on our future operating performance. Based on our existing operating performance we believe this is adequate to meet operational and capital expenditure needs in 2010.

     The credit agreement evidencing our credit facility and the indenture governing our second lien notes contain covenants that include minimum quarterly EBITDA amounts, senior and total debt to EBITDA ratios and an interest coverage ratio. These covenants are subject to a number of exceptions and qualifications set forth in the credit agreement that evidences our credit facility. Please see “—Description of Our Indebtedness.” In addition, the credit agreement and the indenture contain covenants that limit capital expenditures to $6.0 million per quarter, as well as restrict our ability to incur additional debt or sell assets, make certain investments, loans and acquisitions, guarantee

debt, grant liens, enter into transactions with affiliates, engage in other lines of business and pay dividends and distributions. As of March 31, 2010, we were in compliance with each of these covenants.

     Financial Condition and Cash Flows

     Financial Condition

     Our working capital increased $1.7 million to $100.6 million at March 31, 2010 compared to December 31, 2009, primarily due to a $18.6 million increase in accounts receivable, which was partially offset by a $15.0 million increase in accounts payable and $1.3 million increase in accrued liabilities that resulted from higher activity levels in the first quarter of 2010 as compared to fourth quarter of 2009.

     Cash Flows from Operations

     The following table sets forth historical cash flow information for the three months ended March 31, 2009 and 2010 (in thousands):

		Three Months Ended March 31,
		2009				2010
Net cash provided by operations		$	(6,852	)		$	4,236
Net cash used in investing			(9,152	)			(3,888	)
Net cash provided by financing			16,866				(350	)
Change in cash and cash equivalents		$	862			$	(2	)

     Our cash flow provided by operations increased from ($6.9) million for the three months ended March 31, 2009 to $4.2 million for the three months ended March 31, 2010, primarily due to a $6.1 million year-over-year reduction in the loss, which was partially offset by changes in various components of working capital and depreciation expense. As described above in “Our Results of Operations,” lower headcount in the first quarter of 2010 compared to the first quarter of 2009 reduced labor costs by $13.2 million, which favorably impacted net cash provided by operations. Although service activity levels increased during the first quarter of 2010 compared to the first quarter of 2009, the activity increases were almost totally offset by year-over-year increases in sales discounts. Sales discounts increased during 2009 due to increased competition for lower overall levels of service work. Beginning in the first quarter of 2010, we begin to see small reductions in the sales discounts as higher activity levels absorbed excess capacity in many of our operating regions. For a detailed comparison of operating results for the first quarter of 2010 compared to the first quarter of 2009, please see “Our Results of Operations” under the sub-heading “Three Months Ended March 31, 2010 Compared to Three Months Ended March 31, 2009.”

     Cash Flows Used In Investing Activities

     Net cash used in investing activities decreased from $9.2 million for the three months ended March 31, 2009 to $3.9 million for the three months ended March 31, 2010. The decrease was primarily due to lower 2010 capital expenditures, which are currently limited to $6.0 million per quarter under the terms of our credit facility.

     Cash Flows from Financing Activities

     Net cash provided by (used in) financing activities decreased $17.2 million from $16.9 million for the three months ended March 31, 2009 to ($0.4) million for the three months ended March 31, 2010, primarily due to lower net borrowings under our credit facility that resulted from lower levels of capital expenditures during the first quarter of 2010.

     Capital Requirements

     The oilfield services business is capital-intensive, requiring significant investment to expand and upgrade operations. Our capital requirements have consisted primarily of, and we anticipate will continue to be:

•

expansion capital expenditures, such as those to acquire additional equipment and other assets or upgrade existing equipment to grow our business; and

•

maintenance capital expenditures, which are capital expenditures made to extend the useful life of partially or fully depreciated assets or to maintain the operational capabilities of existing assets.

     We continually monitor new advances in pumping equipment and down-hole technology, as well as technologies that may compliment our existing businesses, and commit capital funds to upgrade and purchase additional equipment to meet our customers’ needs. Our total 2010 capital expenditure budget is approximately $24.0 million. In the first quarter of 2010, we made capital expenditures of approximately $5.4 million to purchase new and upgrade existing pumping and down-hole surveying equipment and for maintenance on our existing equipment base. We plan to continue to focus on minimizing our discretionary spending and limiting our capital expenditures given the current operating environment.

     Historically, we have grown through organic expansions and selective acquisitions. Given the current operating conditions and marketplace, as well as the restrictions in our credit facility, we do not anticipate that we will continue to invest significant capital to acquire businesses and assets during 2010. We plan to continue to monitor the economic environment and demand for our services and adjust our business as necessary. We have actively considered a variety of businesses and assets for potential acquisitions and currently we have no agreements or understandings with respect to any acquisition. For a discussion of the primary factors we consider in deciding whether to pursue a particular acquisition or organic expansion project, please read “— Our Long-Term Growth Strategy.” For a discussion of the capital resources and liquidity needed to fund our capital expenditures, as well as the provisions of our indebtedness restricting our ability to make acquisitions and fund capital expenditures, please read “—Liquidity and Capital Resources—General” and “—Description of Our Indebtedness.”

     Off-Balance Sheet Arrangements

     We had no off-balance sheet arrangements as of March 31, 2010 or December 31, 2009.

     Description of Our Indebtedness

     On September 30, 2008, we entered into a credit agreement evidencing our credit facility with a syndicate of financial institutions that provided for a secured revolving credit facility that matures on March 31, 2013. During 2009, we amended the credit agreement twice to prevent potential breaches of the financial covenants contained in the credit agreement. In connection with these amendments, our credit facility was converted into a “borrowing base” facility and the previous financial covenants were replaced with new financial covenants that provided us additional financial flexibility. Under the terms of the most recent amendment, the following changes were made to the credit agreement:

	•		the sale of our fluid logistics services business is now a permitted asset sale;
	•		the total commitment under our credit facility was reduced to $100.0 million, which amount will be further reduced by (i) an additional $25.0 million upon our receipt of a federal income tax refund of $20 million or more and (ii) by an additional $25.0 million upon the sale of our fluid logistics services business;
	•		the definition of “borrowing base” was amended to consist of 80% of eligible accounts receivable plus 20% of the net book value of property, plant and equipment, until such time as the total commitment under the credit facility is reduced to $50.0 million; thereafter the borrowing base will consist solely of 80% of eligible accounts receivable; and
	•		the financial covenants in the credit agreement were revised to require that our required minimum quarterly EBITDA must not be less than: $0, $0, $0 and $10 million for the first, second, third and fourth quarters of 2010, respectively.

The borrowing base under our credit facility is subject to redeterminations by lenders holding at least 51% of the amounts outstanding under our credit facility.

     The interest rate on borrowings under the credit agreement is set, at our option, at either LIBOR plus a spread of 4.0% or the prime lending rate plus a spread of 2.0%. The credit agreement contains financial covenants that we must meet, including the minimum quarterly EBITDA requirements referred to above, senior and total debt to

EBITDA ratios and an interest coverage ratio. These covenants are subject to a number of exceptions and qualifications set forth in the amendment.

     At March 31, 2010, we had $83.5 million outstanding, $6.4 million in letters of credit outstanding and $10.1 million of available capacity under our credit facility. The weighted average interest rate for our credit facility was 4.3% during the three months ended March 31, 2010.

     On April 8, 2010, we received a $34.6 million federal income tax refund which we used to repay a portion of our borrowings under our credit agreement. Under the terms of our credit facility, the receipt of the federal income tax refund reduced the total capacity of our credit facility by $25.0 million to $75.0 million on April 8, 2010.

     In connection with the Diamondback asset acquisition, we issued an aggregate principal amount of $80 million second lien notes due November 2013. In connection with the issuance of our second lien notes, we entered into an indenture with our subsidiaries as guarantors and the Wilmington Trust FSB, as trustee. Interest on our second lien notes accrues at an initial rate of 7% per annum and the rate increases by 1% per annum on each anniversary date of the indenture. Interest is payable quarterly in arrears on January 1, April 1, July 1 and October 1, commencing on January 1, 2009.

     Our credit facility and our second lien notes are both secured by our cash, investment property, accounts receivable, inventory, intangibles and equipment. We are subject to certain limitations under the credit agreement and the indenture, including limitations on our ability to:

	•		make capital expenditures in excess of $6.0 million per quarter through March 2011;
	•		incur additional debt or sell assets;
	•		make certain investments, loans and acquisitions;
	•		guarantee debt;
	•		grant liens;
	•		enter into transactions with affiliates; and
	•		engage in other lines of business.

     A violation of the covenants in the credit agreement would trigger a default that would, absent a waiver or amendment, require immediate repayment of the outstanding indebtedness under our credit facility. Additionally, an event of default under the credit agreement would result in an event of default under the indenture governing our second lien notes, which could require immediate repayment of the outstanding principal and accrued interest on our second lien notes.

Critical Accounting Policies

     The selection and application of accounting policies is an important process that has developed as our business activities have evolved and as the accounting standards have developed. Accounting standards generally do not involve a selection among alternatives, but involve the implementation and interpretation of existing standards, and the use of judgment applied to the specific set of circumstances existing in our business. We make every effort to properly comply with all applicable standards on or before their adoption, and we believe the proper implementation and consistent application of the accounting standards are critical. For further details on our accounting policies, please read Note 2 to the consolidated financial statements included in this report.

     These estimates and assumptions affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the balance sheet date and the amounts of revenue and expenses recognized during the reporting period. We analyze our estimates based on historical experience and various other assumptions that

we believe to be reasonable under the circumstances. However, actual results could differ from such estimates. The following is a discussion of our critical accounting policies.

     Revenue Recognition

     Our revenue is comprised principally of service revenue. Product sales represent approximately 1% of total revenues. Services and products are generally sold based on fixed or determinable pricing agreements with the customer and generally do not include rights of return. Service revenue is recognized, net of discount, when the services are provided and collectability is reasonably assured. Generally our services performed for customers are completed at the customer’s site within one day. We recognize revenue from product sales when the products are delivered to the customer and collectability is reasonably assured. Products are delivered and used by our customers in connection with the performance of our cementing services. Product sale prices are determined by published price lists provided to our customers.

     Accounts receivable are carried at the amount owed by customers. We grant credit to all qualified customers, which are mainly regional, independent oil and natural gas companies. Management periodically reviews accounts receivable for credit risks resulting from changes in the financial condition of our customers. Once an account is deemed not to be collectible, the remaining balance is charged to the reserve account.

     Inventories

     Inventories are stated at the lower of cost or market. Cost primarily represents invoiced costs. We regularly review inventory quantities on hand and record provisions for excess or obsolete inventory based primarily on historical usage, estimated product demand, and technological developments.

     Income Taxes

     We recognize deferred tax liabilities and assets for the expected future tax consequences of events that have been recognized in our financial statements or tax returns. Using this method, deferred tax liabilities and assets were determined based on the difference between the financial carrying amounts and tax bases of assets and liabilities using estimated effective tax rates. Our accounting policies require that a valuation allowance be established when it is more likely than not that all or a portion of a deferred tax asset will not be realized. We evaluate the realizability of our deferred tax assets on a quarterly basis and valuation allowances are provided as necessary. We have not recorded any valuation allowances as of March 31, 2010. Our balance sheets at December 31, 2009 and March 31, 2010 do not include any liabilities associated with uncertain tax positions, and we have no unrecognized tax benefits that if recognized would change our effective tax rate.

     We file income tax returns in the U.S. federal jurisdiction, and various states and local jurisdictions. We are not subject to U.S. federal, state and local income tax examinations by tax authorities for years before 2005. We classify interest related to income tax expense in interest expense and penalties in general and administrative expense. Interest and penalties for the three months ended March 31, 2010 and 2009 were insignificant in each period. We are subject to U.S. federal income tax examinations and we are subject to various state and local tax examinations.

     Property, Plant and Equipment

     Our property, plant and equipment are carried at cost and are depreciated using the straight-line and accelerated methods over their estimated useful lives. The estimated useful lives range from 15 to 30 years for buildings and improvements, 5 to 15 years for disposal wells and equipment and 5 to 10 years for equipment and vehicles. The estimated useful lives may be adversely impacted by technological advances, unusual wear or by accidents during usage. Management routinely monitors the condition of equipment. Historically, management has not changed the estimated useful lives of our property, plant and equipment and presently does not anticipate any significant changes to those estimates. Repairs and maintenance costs, which do not extend the useful lives of the asset, are expensed in the period incurred.

     Impairment of Long-Lived Assets

     We evaluate our long-lived assets, including related intangibles, of identifiable business activities for impairment when events or changes in circumstances indicate, in management’s judgment, that the carrying value of such assets may not be recoverable. The determination of whether impairment has occurred is based on management’s estimate of undiscounted future cash flows attributable to the assets as compared to the carrying value of the assets. For assets identified to be disposed of in the future, the carrying value of these assets is compared to the estimated fair value less the cost to sell to determine if impairment is required. Until the assets are disposed of, an estimate of the fair value is recalculated when related events or circumstances change.

     When determining whether impairment of one of our long-lived assets has occurred, we must estimate the undiscounted cash flows attributable to the asset or asset group. Our estimate of cash flows is based on assumptions regarding the future estimated cash flows, which in most cases is derived from our performance of services. The amount of future business is dependent in part on crude oil and natural gas prices. Projections of our future cash flows are inherently subjective and contingent upon a number of variable factors, including but not limited to:

	•		changes in general economic conditions in regions in which we operate;
	•		the price of crude oil and natural gas;
	•		our ability to negotiate favorable sales arrangements; and
	•		competition from other service providers.

     We currently have not recorded any impairment of any tangible asset. Any significant variance in any of the above assumptions or factors could materially affect our cash flows, which could require us to record an impairment of an asset.

     Goodwill and Other Intangible Assets

     We do not record amortization for goodwill deemed to have an indefinite life for acquisitions completed after June 30, 2001. We perform our goodwill impairment test annually, or more frequently if an event or circumstances would give rise to an impairment indicator. These circumstances include, but are not limited to, significant adverse changes in the business climate. Our goodwill impairment test is performed at the business segment levels, technical services and fluid logistics, as they represent our reporting units. The impairment test is a two-step process. The first step compares the fair value of a reporting unit with its carrying amount, including goodwill, and uses a future cash flow analysis based on the estimates and assumptions for our long-term business forecast. If the fair value of a reporting unit exceeds its carrying amount, the reporting unit’s goodwill is deemed to be not impaired. If the fair value of a reporting unit is less than its carrying amount, the second step of the goodwill impairment test is performed to determine the impairment loss, if any. This second step compares the implied fair value of the reporting unit’s goodwill with the carrying amount of the goodwill, and if the carrying amount of the reporting unit’s goodwill is greater than the implied fair value of that goodwill, an impairment loss is recorded for the difference. Any impairment charge would reduce earnings.

     We performed an assessment of goodwill at December 31, 2008 and the tests resulted in no indications of impairment. However, we determined a “triggering event” requiring an interim assessment had occurred at June 30, 2009 because the oil and gas services industry continued to decline and our net book value had been substantially in excess of our market capitalization during the second quarter of 2009.

     To estimate the fair value of the business segments, we use a weighted-average approach of two commonly used valuation techniques, a discounted cash flow method and a similar transaction method. Our management assigns a weight to the results of each of these methods based on the facts and circumstances that are in existence for that testing period. During the second quarter of 2009, because of overall economic downturn, management assigned more weighting to the discounted cash flow method than the similar transaction method. Given the continued deterioration of the general economic and oil service industry conditions during 2009, management believed that similar transactions may not be as useful because the valuations may reflect distressed sales conditions. Accordingly, the similar transaction weighting was reduced to 10% during the second quarter of 2009.

     In addition to the estimates made by management regarding the weighting of the various valuation techniques, the creation of the techniques themselves requires significant estimates and assumptions to be made by management. The discounted cash flow method, which is assigned the highest weight by management, requires assumptions about future cash flows, future growth rates and discount rates. The assumptions about future cash flows and growth rates are based on our forecasts and strategic plans, as well as the beliefs of management about future activity levels. In applying the discounted cash flow 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 discounted to present value to derive an indication of value of the business enterprise.

     Our intangible assets consist of $7.0 million of customer relationships and non-compete agreements that are amortized over their estimated useful lives which range from three to five years. For the three months ended March 31, 2009 and 2010, we recorded amortization expense of $582,000 and $543,000, respectively.

     Contingent Liabilities

     We record expenses for legal, environmental and other contingent matters when a loss is probable and the cost or range of cost can be reasonably estimated. Judgment is often required to determine when expenses should be recorded for legal, environmental and contingent matters. In addition, we often must estimate the amount of such losses. In many cases, our judgment is based on the input of our legal advisors and on the interpretation of laws and regulations, which can be interpreted differently by governmental regulators and the courts. We monitor known and potential legal, environmental and other contingent matters and make our best estimate of when to record losses for these matters based on available information. Although we continue to monitor all contingencies closely, particularly our outstanding litigation, we currently have no material accruals for contingent liabilities.

     Insurance Expenses

     We partially self-insure employee health insurance plan costs. The estimated costs of claims under this self-insurance program are accrued as the claims are incurred (although actual settlement of the claims may not be made until future periods) and may subsequently be revised based on developments relating to such claims. The self-insurance accrual is estimated based upon our historical experience, as well as any known unpaid claims activity. Judgment is required to determine the appropriate accrual levels for claims incurred but not yet received and paid. The accrual estimates are based primarily upon recent historical experience adjusted for employee headcount changes. Historically, the lag time between the occurrence of an insurance claim and the related payment has been approximately one to two months and the differences between estimates and actuals have not been material. The estimates could be affected by actual claims being significantly different. Presently, we maintain an insurance policy that covers claims in excess of $150,000 per employee.

     Stock-Based Compensation

     We account for equity-based awards using an approach in which the fair value of an award is estimated at the date of grant and recognized as an expense over the requisite service period. Compensation expense is adjusted for equity awards that do not vest because service or performance conditions are not satisfied. Our results of operations for the three months ended March 31, 2009 and 2010 include $737,000 and $865,000 of additional compensation expense, respectively, as a result of the stock based compensation.

     Impact of Inflation

     Inflation can affect the costs of fuel, raw materials and equipment that we purchase for use in our business. Historically, we were generally able to pass along any cost increases to our customers, although due to pricing commitments and the timing of our marketing and bidding cycles there is generally a delay of several weeks or months from the time that we incur a cost increase until the time we can pass it along to our customers. Most of our property and equipment was acquired in recent years, so recorded depreciation approximates depreciation based on current dollars. Management is of the opinion that inflation has not had a significant impact on our business.

Non-GAAP Accounting Measures

     The following table presents a reconciliation of Adjusted EBITDA to net income (loss) for each of the periods indicated:

		Three Months Ended
		March 31,
		2009				2010
Reconciliation of Adjusted EBITDA to Net Income (Loss):
Net income (loss)		$	(14,711	)		$	(8,652	)
Income tax expense (benefit)			(7,752	)			(4,525	)
Interest expense			3,176				2,902
Stock compensation expense			737				865
Depreciation, amortization and accretion			17,485				19,787
Adjusted EBITDA(1)		$	(1,065	)		$	10,377

Item 3. Quantitative and Qualitative Disclosures about Market Risk.

     Market risk is the risk of loss arising from adverse changes in market rates and prices. The principal market risk to which we are exposed is the risk related to interest rate fluctuations. To a lesser extent, we are also exposed to risks related to increases in the prices of fuel and raw materials consumed in performing our services. We do not engage in commodity price hedging activities.

     Interest Rate Risk. We are exposed to changes in interest rates as a result of our floating rate borrowings, each of which have variable interest rates based upon, at our option, LIBOR or the prime lending rate. The impact of a 1% increase in interest rates on our outstanding debt as of December 31, 2009 and March 31, 2010 would result in an increase in interest expense and a corresponding decrease in net income, of less than $1.0 million and $1.0 million annually, respectively.

     Concentration of Credit Risk. Substantially all of our customers are engaged in the oil and gas industry. This concentration of customers may impact our overall exposure to credit risk, either positively or negatively, in that customers may be similarly affected by changes in economic and industry conditions. Two customers individually accounted for 22% and 12% our revenue for the three months ended March 31, 2009. During the three months ended March 31, 2010 no single customer accounted for more than 10% of our revenue. At December 31, 2009, two customers accounted for 23% and 12% and eight customers collectively accounted for 62% of our accounts receivable, respectively. At March 31, 2010, one customer accounted for 13% and eight customers collectively accounted for 57% of our accounts receivable, respectively.

     Commodity Price Risk. Our fuel and material purchases expose us to commodity price risk. Our material costs primarily include the cost of inventory consumed while performing our stimulation, nitrogen and cementing services such as frac sand, cement and nitrogen. On January 14, 2010, we amended our sand purchase agreement with Preferred Rocks USS, Inc. to hedge costs related to fluctuating sand prices. Our fuel costs consist primarily of diesel fuel used by our various trucks and other motorized equipment. The prices for fuel and the raw materials in our inventory are volatile and are impacted by changes in supply and demand, as well as market uncertainty and regional shortages. Historically we were generally able to pass along price increases to our customers, due to pricing commitments and the timing of our marketing and bidding cycles there is generally a delay of several weeks or months from the time that we incur a price increase until the time that we can pass it along to our customers. Given the current economic conditions and the decline in the overall demand for certain types of our services, in most cases we are currently unable to pass these price increases on to our customers.

Item 4. Controls and Procedures.

     Evaluation of Disclosure Controls and Procedures. We have established disclosure controls and procedures designed to ensure that material information required to be disclosed in our reports filed under the Exchange Act is

recorded, processed, summarized and reported within the time periods specified by the SEC and that any material information relating to us is recorded, processed, summarized and reported to our management including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosures. In designing and evaluating our disclosure controls and procedures, our management recognizes that controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving desired control objectives. In reaching a reasonable level of assurance, our management necessarily was required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.

     As required by SEC rule 13a-15(b), we have evaluated, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Our Chief Executive Officer and Chief Financial Officer, based upon their evaluation as of March 31, 2010, the end of the period covered in this report, concluded that our disclosure controls and procedures were effective based on a reasonable assurance level.

     Changes in Internal Control over Financial Reporting. There were no changes in our system of internal control over financial reporting that occurred during our second fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II — OTHER INFORMATION

Item 1. Legal Proceedings.

     We are named as a defendant, from time to time, in litigation that arises in the ordinary course of business. Our management is not aware of any significant litigation, pending or threatened, that would have a material adverse effect on our financial position, results of operations, or cash flows.

Item 1A. Risk Factors

     You should consider carefully the risks and uncertainties described in our Annual Report on Form 10-K for the year ended December 31, 2009, under Item 1A, “Risk Factors,” which could materially adversely affect our business, financial condition and results of operations. While these are the risks and uncertainties we believe are most important, you should know that they are not the only risks or uncertainties facing us or that may adversely affect our business. Additional risks and uncertainties not presently known to us or that we currently deem immaterial also could impair our business operations and financial condition. If any of these risks or uncertainties were to occur, our business, financial condition or results of operation could be adversely affected.

Item 2. Unregistered Sale of Equity Securities.

     From time to time since June 6 2006, our defined contribution profit sharing/401(k) retirement plan purchased 43,780 shares of our common stock on the open market for participants in the plan for aggregate consideration of $651,000.

Item 6. Exhibits.

     See the Index to Exhibits included with this report.

SIGNATURES

     Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on the 6th day of May, 2010.

INDEX TO EXHIBITS
OF
SUPERIOR WELL SERVICES, INC.

(a) Exhibits

3.1		Amended and Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.1 to Form 8-K (SEC File No. 000-51435) filed on August 3, 2005).
3.2		Amended and Restated Bylaws (incorporated by reference to Exhibit 3.2 to Form 8-K (SEC File No. 000-51435) filed on August 3, 2005).
3.3		Certificate of Designations for Series A 4% Convertible Preferred Stock (incorporated by reference to Exhibit 3.1 to Form 8-K filed on November 21, 2008).
4.1		Specimen Stock Certificate representing our common stock (incorporated by reference to Exhibit 4.1 to Registration Statement on Form S-1/A (Registration No. 333-124674) filed on June 24, 2005).
4.2		Registration Rights Agreement dated as of July 28, 2005 by and among the Superior Well Services, Inc. and the stockholders signatory thereto (incorporated by reference to Exhibit 10.1 to Form 8-K (SEC File No. 000-51435) filed on August 3, 2005).
4.3†		Form of Restricted Stock Agreement for Employees without Employment Agreements (filed as Exhibit 4.1 to Registration Statement on Form S-8 (Registration No. 333-130615) filed on December 22, 2005).
4.4†		Form of Restricted Stock Agreement for Executives with Employment Agreements (filed as Exhibit 4.2 to Registration Statement on Form S-8 (Registration No. 333-130615) filed on December 22, 2005).
4.5†		Form of Restricted Stock Agreement for Non-Employee Directors (filed as Exhibit 4.3 to Registration Statement on Form S-8 (Registration No. 333-130615) filed on December 22, 2005).
4.6*		Superior Well Services, Inc. Amended and Restated Incentive Compensation Plan, effective May 4, 2010.
4.7		Indenture, dated as of November 18, 2008, between Superior Well Services, Inc. and its Subsidiaries and Wilmington Trust FSB (as Trustee and Collateral Agent), relating to the Second Lien Notes due 2013 (incorporated by reference to Exhibit 4.1 to Form 8-K (SEC File No. 000-51435) filed on November 21, 2008).
10.1†		Amended and Restated Employment Agreement between David E. Wallace and Superior Well Services, Inc. dated September 15, 2008 (incorporated by reference to Exhibit 10.1 to Form 8-K (SEC File No. 000-51435) filed on September 18, 2008).
10.2†		Amended and Restated Employment Agreement between Jacob Linaberger and Superior Well Services, Inc. dated September 15, 2008 (incorporated by reference to Exhibit 10.2 to Form 8-K (SEC File No. 000-51435) filed on September 18, 2008).
10.3†		Amended and Restated Employment Agreement between Thomas W.Stoelk and Superior Well Services, Inc. dated September 15, 2008 (incorporated by reference to Exhibit 10.4 to Form 8-K (SEC File No. 000-51435) filed on September 18, 2008).
10.4†		Amended and Restated Employment Agreement between Rhys R. Reese and Superior Well Services, Inc. dated September 15, 2008 (incorporated by reference to Exhibit 10.3 to Form 8-K (SEC File No. 000-51435) filed on September 18, 2008).
10.5†		Indemnification Agreement between David E. Wallace and Superior Well Services, Inc., dated August 3, 2005 (incorporated by reference to Exhibit 10.7 to Form 8-K (SEC File No. 000-51435) filed on August 3, 2005).

10.6†		Indemnification Agreement between Jacob B. Linaberger and Superior Well Services, Inc., dated August 3, 2005 (incorporated by reference to Exhibit 10.8 to Form 8-K (SEC File No. 000-51435) filed on August 3, 2005).
10.7†		Indemnification Agreement between Thomas W .Stoelk and Superior Well Services, Inc., dated August 3, 2005 (incorporated by reference to Exhibit 10.9 to Form 8-K (SEC File No. 000-51435) filed on August 3, 2005).
10.8†		Indemnification Agreement between Rhys R. Reese and Superior Well Services, Inc., dated August 3, 2005 (incorporated by reference to Exhibit 10.10 to Form 8-K (SEC File No. 000-51435) filed on August 3, 2005).
10.9†		Indemnification Agreement between Mark A. Snyder and Superior Well Services, Inc., dated August 3, 2005 (incorporated by reference to Exhibit 10.12 to Form 8-K (SEC File No. 000-51435) filed on August 3, 2005).
10.10†		Indemnification Agreement between David E. Snyder and Superior Well Services, Inc., dated August 3, 2005 (incorporated by reference to Exhibit 10.13 to Form 8-K (SEC File No. 000-51435) filed on August 3, 2005).
10.11†		Indemnification Agreement between Charles C. Neal and Superior Well Services, Inc., dated August 3, 2005 (incorporated by reference to Exhibit 10.14 to Form 8-K (SEC File No. 000-51435) filed on August 3, 2005).
10.12†		Indemnification Agreement between John A. Staley, IV and Superior Well Services, Inc., dated August 3, 2005 (incorporated by reference to Exhibit 10.15 to Form 8-K (SEC File No. 000-51435) filed on August 3, 2005).
10.13†		Indemnification Agreement between Anthony J. Mendicino and Superior Well Services, Inc. dated August 30, 2005 (incorporated by reference to Exhibit 10.16 to Superior’s Quarterly Report on Form 10-Q (SEC File No. 000-51435) filed on September 1, 2005).
10.14†		Employment Agreement between Daniel Arnold and Superior Well Services, Inc., dated May 14, 2007 (incorporated by reference to Exhibit 10.1 to Superior’s Quarterly Report on Form 10-Q (SEC File No. 000-51435) filed on August 8, 2007).
10.15†		Indemnification Agreement between Daniel Arnold and Superior Well Services, Inc. dated May 14, 2007 (incorporated by reference to Exhibit 10.2 to Superior’s Quarterly Report on Form 10-Q (SEC File No. 000-51435) filed on August 8, 2007).
10.16†		Employment Agreement between Michal J. Seyman and Superior Well Services Inc. dated December 21, 2009 (incorporated by reference to Exhibit 10.1 to Form 8-K (SEC File No. 000-51435) filed on December 24, 2009).
10.17†		Non-Employee Director Compensation Summary (incorporated by reference to Exhibit 10.30 to Annual Report on Form 10-K filed on March 11, 2008).
10.18		Agreement dated October 2, 2007 between U.S. Silica and Superior Well Services, Inc. (incorporated by reference to Exhibit 10.30 to Annual Report on Form 10-K (SEC File No. 000-51435) filed on March 11, 2008).
10.19		Revolving Credit Agreement among Superior Well Services Inc., Lenders Party, Citizens Bank of Pennsylvania (as Administrative Agent) and RBS Securities Corporation dated as of September 30, 2008 (incorporated by reference to Exhibit 10.1 to Form 8-K (SEC File No. 000-51435) filed on October 3, 2008).

10.20		First Amendment to Credit Agreement by and among Superior Well Services, Inc., the Lenders party thereto, Citizens Bank of Pennsylvania, as Administrative Agent, and RBS Securities, Inc., as Sole Lead Arranger (incorporated by reference to Exhibit 10.1 to Form 8-K (SEC File No. 000-51435) filed on September 24, 2009).
10.21		Second Amendment to Credit Agreement by and among Superior Well Services, Inc., the Lenders party thereto, Citizens Bank of Pennsylvania, as Administrative Agent, and RBS Securities, Inc., as Sole Lead Arranger (incorporated by reference to Exhibit 10.1 to Form 8-K (SEC File No. 000-51435) filed on December 24, 2009).
10.22		Asset Purchase Agreement among Superior Well Services, Inc., Superior Well Services, Ltd., Diamondback Holdings, LLC and Diamondback’s Subsidiaries dated September 15, 2008 (incorporated by reference to Exhibit 10.1 to Form 8-K (SEC File No. 000-51435) filed on September 18, 2008).
10.23		First Amendment to Asset Purchase Agreement entered into by Superior Well Services, Inc. and Superior Well Services, Ltd. and Diamondback Holdings, LLC and its Subsidiaries on November 18, 2008 (incorporated by reference to Exhibit 10.1 to Form 8-K (SEC File No. 000-51435) filed on November 21, 2008).
10.24		Registration Rights Agreement dated November 18, 2008 among Superior Well Services, Inc., Designated Holders and Diamondback Holdings, LLC (incorporated by reference to Exhibit 10.2 to Form 8-K (SEC File No. 000-51435) filed on November 21, 2008).
10.25		Sand Purchase Agreement dated October 10, 2008 among Superior Well Services, Inc. and Preferred Rocks USS, Inc. and U.S. Silica Company (incorporated by reference to Exhibit 10.1 to Form 10-Q (SEC File No. 000-51435) filed on November 4, 2008).
10.26‡		Amendment No. 1 to Sand Purchase Agreement among Superior Well Services, Inc. and Preferred Rocks USS, Inc., dated January 14, 2010.
12.1		Ratio of Earnings to Fixed Charges and Earnings to Fixed Charges and Preference Securities Dividends
21.1		List of Subsidiaries
23.1		Consent of Independent Registered Public Accounting Firm
24.1		Power of Attorney (included on signature page hereto).
31.1*		Sarbanes-Oxley Section 302 certification of David E. Wallace for Superior Well Services, Inc. for the March 31, 2010 Quarterly Report on Form 10-Q.
31.2*		Sarbanes-Oxley Section 302 certification of. Thomas W.Stoelk for Superior Well Services, Inc. for the March 31, 2010 Quarterly Report on Form 10-Q.
32.1**		Sarbanes-Oxley Section 906 certification of David E. Wallace for Superior Well Services, Inc. for the March 31, 2010 Quarterly Report on Form 10-Q.
32.2**		Sarbanes-Oxley Section 906 certification of Thomas W.Stoelk for Superior Well Services, Inc. for the March 31, 2010 Quarterly Report on Form 10-Q.