(Former name, former address and former fiscal year, if changed since last report)

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

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 (section 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes R No ¨

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

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

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

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

	March 31,			December 31,
	2015			2014
ASSETS
Current assets:
Cash and cash equivalents	$	86,917		$	43,012
Accounts receivable, net of allowance for doubtful accounts of $3,537 and $3,546 at March 31, 2015 and December 31, 2014, respectively		484,986			663,404
Federal and state income taxes receivable		—			81,726
Inventory		28,346			32,251
Deferred tax assets, net		39,926			37,075
Other		47,445			51,624
Total current assets		687,620			909,092
Property and equipment, net		4,222,404			4,131,071
Goodwill and intangible assets		219,902			220,813
Deposits on equipment purchases		80,159			112,379
Other		20,822			20,656
Total assets	$	5,230,907		$	5,394,011
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	315,746		$	382,438
Federal and state income taxes payable		30,994			—
Accrued expenses		178,876			173,466
Current portion of long-term debt		35,000			12,500
Total current liabilities		560,616			568,404
Borrowings under revolving credit facility		—			303,000
Other long-term debt		845,000			670,000
Deferred tax liabilities, net		914,711			935,660
Other		12,042			11,137
Total liabilities		2,332,369			2,488,201
Commitments and contingencies (see Note 9)
Stockholders' equity:
Preferred stock, par value $.01; authorized 1,000,000 shares, no shares issued		—			—
Common stock, par value $.01; authorized 300,000,000 shares with 189,265,286 and 189,262,876 issued and 146,446,701 and 146,444,291 outstanding at March 31, 2015 and December 31, 2014		1,893			1,893
Additional paid-in capital		991,495			984,674
Retained earnings		2,806,300			2,811,815
Accumulated other comprehensive income		(2,115	)		6,463
Treasury stock, at cost, 42,818,585 shares at March 31, 2015 and December 31, 2014		(899,035	)		(899,035	)
Total stockholders' equity		2,898,538			2,905,810
Total liabilities and stockholders' equity	$	5,230,907		$	5,394,011

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

	Three Months Ended
	March 31,
	2015			2014
Operating revenues:
Contract drilling	$	401,478		$	425,903
Pressure pumping		249,721			240,261
Oil and natural gas		6,500			12,004
Total operating revenues		657,699			678,168
Operating costs and expenses:
Contract drilling		212,810			251,059
Pressure pumping		212,725			199,808
Oil and natural gas		2,798			3,274
Depreciation, depletion, amortization and impairment		175,382			147,322
Selling, general and administrative		32,797			19,673
Net gain on asset disposals		(2,916	)		(1,744	)
Total operating costs and expenses		633,596			619,392
Operating income		24,103			58,776
Other income (expense):
Interest income		283			176
Interest expense, net of amount capitalized		(8,541	)		(7,188	)
Total other expense		(8,258	)		(7,012	)
Income before income taxes		15,845			51,764
Income tax expense (benefit):
Current		30,520			26,935
Deferred		(23,800	)		(9,993	)
Total income tax expense		6,720			16,942
Net income	$	9,125		$	34,822
Net income per common share:
Basic	$	0.06		$	0.24
Diluted	$	0.06		$	0.24
Weighted average number of common shares outstanding:
Basic		144,983			142,892
Diluted		145,745			145,099
Cash dividends per common share	$	0.10		$	0.10

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

												Accumulated
	Common Stock					Additional						Other
	Number of					Paid-in			Retained			Comprehensive			Treasury
	Shares			Amount		Capital			Earnings			Income			Stock			Total
Balance, December 31, 2014		189,263		$	1,893	$	984,674		$	2,811,815		$	6,463		$	(899,035	)		2,905,810
Net income	—			—		—				9,125		—			—				9,125
Foreign currency translation adjustment	—			—		—			—				(8,578	)	—				(8,578	)
Issuance of restricted stock		18			—		—		—			—			—			—
Forfeitures of restricted stock		(16	)		—		—		—			—			—				—
Stock-based compensation	—				—		6,855		—			—			—				6,855
Tax expense related to stock-based compensation	—			—			(34	)	—			—			—				(34	)
Payment of cash dividends	—			—		—				(14,640	)	—			—				(14,640	)
Balance, March 31, 2015		189,265		$	1,893	$	991,495		$	2,806,300		$	(2,115	)	$	(899,035	)	$	2,898,538

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

	Three Months Ended
	March 31,
	2015			2014
Cash flows from operating activities:
Net income	$	9,125		$	34,822
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, amortization and impairment		175,382			147,322
Tax expense on stock based compensation		(34	)		—
Dry holes and abandonments		46			283
Deferred income tax (benefit) expense		(23,800	)		(9,993	)
Stock-based compensation expense		6,855			6,711
Net gain on asset disposals		(2,916	)		(1,744	)
Changes in operating assets and liabilities:
Accounts receivable		176,672			(35,434	)
Income taxes receivable/payable		112,711			14,180
Inventory and other assets		9,724			2,513
Accounts payable		(65,196	)		22,264
Accrued expenses		5,559			(1,648	)
Other liabilities		857			221
Net cash provided by operating activities		404,985			179,497
Cash flows from investing activities:
Purchases of property and equipment		(241,466	)		(170,372	)
Proceeds from disposal of assets		5,827			6,590
Net cash used in investing activities		(235,639	)		(163,782	)
Cash flows from financing activities:
Purchases of treasury stock		—			(43	)
Dividends paid		(14,640	)		(14,456	)
Tax benefit related to stock-based compensation		—			1,961
Debt issuance costs		(1,940	)		—
Proceeds from long-term debt		200,000			—
Repayment of long-term debt		(2,500	)		(2,500	)
Proceeds from borrowings under revolving credit facility		54,000			—
Repayment of borrowings under revolving credit facility		(357,000	)		—
Proceeds from exercise of stock options		—			8,033
Net cash provided by (used in) financing activities		(122,080	)		(7,005	)
Effect of foreign exchange rate changes on cash		(3,361	)		(473	)
Net increase in cash and cash equivalents		43,905			8,237
Cash and cash equivalents at beginning of period		43,012			249,509
Cash and cash equivalents at end of period	$	86,917		$	257,746
Supplemental disclosure of cash flow information:
Net cash (paid) received during the period for:
Interest, net of capitalized interest of $1,592 in 2015 and $1,667 in 2014	$	(783	)	—
Income taxes	$	83,135		$	(10,001	)
Non-cash investing and financing activities:
Net (decrease) increase in payables for purchases of property and equipment	$	(884	)	$	68,802
Net decrease (increase) in deposits on equipment purchases	$	32,220		$	(4,677	)

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

The unaudited interim consolidated condensed financial statements include the accounts of Patterson-UTI Energy, Inc. (the “Company”) and its wholly-owned subsidiaries. All significant intercompany accounts and transactions have been eliminated. Except for wholly-owned subsidiaries, the Company has no controlling financial interests in any entity which would require consolidation.

The unaudited interim consolidated condensed financial statements have been prepared by management of the Company pursuant to the rules and regulations of the Securities and Exchange Commission. Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been omitted pursuant to such rules and regulations, although the Company believes the disclosures included either on the face of the financial statements or herein are sufficient to make the information presented not misleading. In the opinion of management, all adjustments which are of a normal recurring nature considered necessary for a fair statement of the information in conformity with accounting principles generally accepted in the United States of America have been included. The Unaudited Consolidated Condensed Balance Sheet as of December 31, 2014, as presented herein, was derived from the audited consolidated balance sheet of the Company, but does not include all disclosures required by accounting principles generally accepted in the United States of America. These unaudited consolidated condensed financial statements should be read in conjunction with the consolidated financial statements and related notes included in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2014. The results of operations for the three months ended March 31, 2015 are not necessarily indicative of the results to be expected for the full year.

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

The carrying values of cash and cash equivalents, trade receivables and accounts payable approximate fair value.

The Company provides a dual presentation of its net income per common share in its unaudited consolidated condensed statements of operations: Basic net income per common share (“Basic EPS”) and diluted net income per common share (“Diluted EPS”).

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

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

The following table presents information necessary to calculate net income per share for the three months March 31, 2015 and 2014 as well as potentially dilutive securities excluded from the weighted average number of diluted common shares outstanding because their inclusion would have been anti-dilutive (in thousands, except per share amounts):

	Three Months Ended
	March 31,
	2015			2014
BASIC EPS:
Net income	$	9,125		$	34,822
Adjust for income attributed to holders of non-vested restricted stock		(86	)		(353	)
Income attributed to common stockholders	$	9,039		$	34,469
Weighted average number of common shares outstanding, excluding non-vested shares of restricted stock		144,983			142,892
Basic net income per common share	$	0.06		$	0.24
DILUTED EPS:
Income attributed to common stockholders	$	9,039		$	34,469
Weighted average number of common shares outstanding, excluding non-vested shares of restricted stock		144,983			142,892
Add dilutive effect of potential common shares		762			2,207
Weighted average number of diluted common shares outstanding		145,745			145,099
Diluted net income per common share	$	0.06		$	0.24
Potentially dilutive securities excluded as anti-dilutive		5,569			80

The Company uses share-based payments to compensate employees and non-employee directors. The Company recognizes the cost of share-based payments under the fair-value-based method. Share-based awards consist of equity instruments in the form of stock options, restricted stock or restricted stock units and have included service and, in certain cases, performance conditions. The Company’s share-based awards also included share-settled performance unit awards. Share-settled performance unit awards are accounted for as equity awards. The Company issues shares of common stock when vested stock options are exercised, when restricted stock is granted and when restricted stock units and share-settled performance unit awards vest.

Stock Options — The Company estimates the grant date fair values of stock options using the Black-Scholes-Merton valuation model. Volatility assumptions are based on the historic volatility of the Company’s common stock over the most recent period equal to the expected term of the options as of the date the options are granted. The expected term assumptions are based on the Company’s experience with respect to employee stock option activity. Dividend yield assumptions are based on the expected dividends at the time the options are granted. The risk-free interest rate assumptions are determined by reference to United States Treasury yields. Weighted-average assumptions used to estimate the grant date fair values for stock options granted for the three month periods ended March 31, 2015 and 2014 follow:

			Weighted
			Average
	Underlying		Exercise
	Shares		Price
Outstanding at January 1, 2015		6,086,250	$	22.32
Granted		60,000	$	16.59
Exercised		—		—
Cancelled		—		—
Expired		—		—
Outstanding at March 31, 2015		6,146,250	$	22.26
Exercisable at March 31, 2015		5,390,683	$	21.44

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

Restricted Stock Units — For all restricted stock unit awards made to date, shares of common stock are not issued until the units vest. Restricted stock units are subject to forfeiture for failure to fulfill service conditions. Non-forfeitable cash dividend equivalents are paid on certain non-vested restricted stock units. The Company uses the straight-line method to recognize periodic compensation cost over the vesting period.

Performance Unit Awards — In 2011, 2012, 2013 and 2014, the Company granted stock-settled performance unit awards to certain executive officers (the “Stock-Settled Performance Units”). The Stock-Settled Performance Units provide for the recipients to receive a grant of shares of stock upon the achievement of certain performance goals established by the Compensation Committee during the performance period. The performance units will only have a payout if total shareholder return is positive for the performance period and, when compared to the peer group, is at or above the 25th percentile. The performance period for the Stock-Settled Performance Units is the three year period commencing on April 1 of the year of grant. For the 2012 and 2013 Stock-Settled Performance Units, the performance period can extend for an additional two years in certain circumstances. The performance goals for the Stock-Settled Performance Units are tied to the Company’s total shareholder return for the performance period as compared to total shareholder return for a peer group determined by the Compensation Committee. These goals are considered to be market conditions under the relevant accounting standards and the market conditions were factored into the determination of the fair value of the performance units. Generally, the recipients will receive a target number of shares if the Company’s total shareholder return is positive and, when compared to the peer group, is at the 50^th percentile and two times the target if at the 75^th percentile or higher. If the Company’s total shareholder return is positive, and, when compared to the peer group, is at the 25^th percentile, the recipients will only receive one-half of the target number of shares. The grant of shares when achievement is between the 25^th and 75^th percentile will be determined on a pro-rata basis. The target number of shares with respect to the 2012 Stock-Settled Performance Units was 192,000. The performance period for the 2012 Stock-Settled Performance Units ended on March 31, 2015, and the Company’s total shareholder return was at the 87^th percentile. In April 2015, 384,000 shares were issued to settle the 2012 Stock-Settled Performance Units.

The total target number of shares with respect to the Stock-Settled Performance Units is set forth below:

Because the performance units are stock-settled awards, they are accounted for as equity awards and measured at fair value on the date of grant using a Monte Carlo simulation model. The fair value of the Stock-Settled Performance Units is set forth below (in thousands):

These fair value amounts are charged to expense on a straight-line basis over the performance period. Compensation expense associated with the Stock-Settled Performance Units is shown below (in thousands):

Property and equipment consisted of the following at March 31, 2015 and December 31, 2014 (in thousands):

The Company’s revenues, operating profits and identifiable assets are primarily attributable to three business segments: (i) contract drilling of oil and natural gas wells, (ii) pressure pumping services and (iii) the investment, on a non-operating working interest basis, in oil and natural gas properties. Each of these segments represents a distinct type of business. These segments have separate management teams which report to the Company’s chief operating decision maker. The results of operations in these segments are regularly reviewed by the chief operating decision maker for purposes of determining resource allocation and assessing performance. Separate financial data for each of our business segments is provided in the table below (in thousands):

	Three Months Ended
	March 31,
	2015			2014
Revenues:
Contract drilling	$	402,241		$	426,961
Pressure pumping		249,721			240,261
Oil and natural gas		6,500			12,004
Total segment revenues		658,462			679,226
Elimination of intercompany revenues (a)		(763	)		(1,058	)
Total revenues	$	657,699		$	678,168

Income before income taxes:
Contract drilling	$	56,138		$	67,077
Pressure pumping		(15,016	)		1,543
Oil and natural gas		(4,562	)		2,703
		36,560			71,323
Corporate and other		(15,373	)		(14,291	)
Net gain on asset disposals (b)		2,916			1,744
Interest income		283			176
Interest expense		(8,541	)		(7,188	)
Other	—			—
Income before income taxes	$	15,845		$	51,764

Goodwill — Goodwill by operating segment as of March 31, 2015 and changes for the three months then ended are as follows (in thousands):

There were no accumulated impairment losses as of March 31, 2015 or December 31, 2014.

Goodwill is evaluated at least annually on December 31, or when circumstances require, to determine if the fair value of recorded goodwill has decreased below its carrying value. For purposes of impairment testing, goodwill is evaluated at the reporting unit level. The Company’s reporting units for impairment testing have been determined to be its operating segments. The Company first determines whether it is more likely than not that the fair value of a reporting unit is less than its carrying value after considering qualitative, market and other factors. If so, then goodwill impairment is determined using a two-step impairment test. From time to time, the Company may perform the first step of the quantitative testing for goodwill impairment in lieu of performing the qualitative assessment. The first step is to compare the fair value of an entity’s reporting units to the respective carrying value of those reporting units. If the carrying value of a reporting unit exceeds its fair value, the second step of the impairment test is performed whereby the fair value of the reporting unit is allocated to its identifiable tangible and intangible assets and liabilities with any remaining fair value representing the fair value of goodwill. If this resulting fair value of goodwill is less than the carrying value of goodwill, an impairment loss would be recognized in the amount of the shortfall.

Intangible Assets — Intangible assets were recorded in the pressure pumping operating segment in connection with the fourth quarter 2010 acquisition of the assets of a pressure pumping business. As a result of the purchase price allocation, the Company recorded an intangible asset related to the customer relationships acquired. The intangible asset was recorded at fair value on the date of acquisition.

The value of the customer relationships was estimated using a multi-period excess earnings model to determine the present value of the projected cash flows associated with the customers in place at the time of the acquisition and taking into account a contributory asset charge. The resulting intangible asset is being amortized on a straight-line basis over seven years. Amortization expense of approximately $911,000 was recorded in the three months ended March 31, 2015 and 2014 associated with customer relationships.

The following table presents the gross carrying amount and accumulated amortization of the customer relationships as of March 31, 2015 and December 31, 2014 (in thousands):

	March 31, 2015							December 31, 2014
	Gross					Net		Gross					Net
	Carrying		Accumulated			Carrying		Carrying		Accumulated			Carrying
	Amount		Amortization			Amount		Amount		Amortization			Amount
Customer relationships	$	25,500	$	(16,393	)	$	9,107	$	25,500	$	(15,482	)	$	10,018

Accrued expenses consisted of the following at March 31, 2015 and December 31, 2014 (in thousands):

The Company records a liability for the estimated costs to be incurred in connection with the abandonment of oil and natural gas properties in the future. This liability is included in the caption “other” in the liabilities section of the consolidated condensed balance sheet. The following table describes the changes to the Company’s asset retirement obligations during the three months ended March 31, 2015 and 2014 (in thousands):

Credit Facilities — On September 27, 2012, the Company entered into a Credit Agreement (as amended, the “Credit Agreement”) with Wells Fargo Bank, N.A., as administrative agent, letter of credit issuer, swing line lender and lender, and each of the other lenders party thereto. The Credit Agreement is a committed senior unsecured credit facility that includes a revolving credit facility and a term loan facility.

The revolving credit facility permits aggregate borrowings of up to $500 million outstanding at any time. The revolving credit facility contains a letter of credit facility that is limited to $150 million and a swing line facility that is limited to $40 million, in each case outstanding at any time.

The term loan facility provides for a loan of $100 million, which was drawn on December 24, 2012. The term loan facility is payable in quarterly principal installments, which commenced December 27, 2012. The installment amounts vary from 1.25% of the original principal amount for each of the first four quarterly installments, 2.50% of the original principal amount for each of the subsequent eight quarterly installments, 5.00% of the original principal amount for the subsequent four quarterly installments and 13.75% of the original principal amount for the final four quarterly installments.

Subject to customary conditions, the Company may request that the lenders’ aggregate commitments with respect to the revolving credit facility and/or the term loan facility be increased by up to $100 million, not to exceed total commitments of $700 million. The maturity date under the Credit Agreement is September 27, 2017 for both the revolving facility and the term facility.

Loans under the Credit Agreement bear interest by reference, at the Company’s election, to the LIBOR rate or base rate, provided, that swing line loans bear interest by reference only to the base rate. The applicable margin on LIBOR rate loans varies from 2.25% to 3.25% and the applicable margin on base rate loans varies from 1.25% to 2.25%, in each case determined based upon the Company’s debt to capitalization ratio. As of March 31, 2015 the applicable margin on LIBOR rate loans was 2.25% and the applicable margin on base rate loans was 1.25%. Based on the Company’s debt to capitalization ratio at December 31, 2014, the applicable margin on LIBOR loans is 2.75% and the applicable margin on base rate loans is 1.75% as of April 1, 2015. Based on the Company’s debt to capitalization ratio at March 31, 2015, the applicable margin on LIBOR loans will be 2.25% and the applicable margin on base rate loans will be 1.25% as of July 1, 2015. A letter of credit fee is payable by the Company equal to the applicable margin for LIBOR rate loans times the daily amount available to be drawn under outstanding letters of credit. The commitment fee rate payable to the lenders for the unused portion of the credit facility is 0.50%.

Each domestic subsidiary of the Company will unconditionally guarantee all existing and future indebtedness and liabilities of the other guarantors and the Company arising under the Credit Agreement, other than (a) Ambar Lone Star Fluid Services LLC, (b) domestic subsidiaries that directly or indirectly have no material assets other than equity interests in, or capitalization indebtedness owed by, foreign subsidiaries, and (c) any subsidiary having total assets of less than $1 million. Such guarantees also cover obligations of the Company and any subsidiary of the Company arising under any interest rate swap contract with any person while such person is a lender or an affiliate of a lender under the Credit Agreement.

The Credit Agreement requires compliance with two financial covenants. The Company must not permit its debt to capitalization ratio to exceed 45%. The Credit Agreement generally defines the debt to capitalization ratio as the ratio of (a) total borrowed money indebtedness to (b) the sum of such indebtedness plus consolidated net worth, with consolidated net worth determined as of the last day of the most recently ended fiscal quarter. The Company also must not permit the interest coverage ratio as of the last day of a fiscal quarter to be less than 3.00 to 1.00. The Credit Agreement generally defines the interest coverage ratio as the ratio of earnings before interest, taxes, depreciation and amortization (“EBITDA”) of the four prior fiscal quarters to interest charges for the same period. The Company was in compliance with these covenants at March 31, 2015. The Credit Agreement also contains customary representations, warranties and affirmative and negative covenants.

Events of default under the Credit Agreement include failure to pay principal or interest when due, failure to comply with the financial and operational covenants, as well as a cross default event, loan document enforceability event, change of control event and bankruptcy and other insolvency events. If an event of default occurs and is continuing, then a majority of the lenders have the right, among others, to (i) terminate the commitments under the Credit Agreement, (ii) accelerate and require the Company to repay all the outstanding amounts owed under any loan document (provided that in limited circumstances with respect to insolvency and bankruptcy of the Company, such acceleration is automatic), and (iii) require the Company to cash collateralize any outstanding letters of credit.

As of March 31, 2015, the Company had $80.0 million principal amount outstanding under the term loan facility at an interest rate of 2.625% and no amounts outstanding under the revolving credit facility. The $39.8 million in letters of credit previously outstanding under the Credit Agreement have been replaced as discussed below and, as a result, the Company currently has available borrowing capacity of $500 million.

On March 16, 2015, the Company entered into a Reimbursement Agreement (the “Reimbursement Agreement”) with The Bank of Nova Scotia (“Scotiabank”), pursuant to which the Company may from time to time request that Scotiabank issue an unspecified amount of letters of credit. The letters of credit previously outstanding under the Credit Agreement have been replaced by letters of credit issued under the Reimbursement Agreement. The Company expects that any future requests for letters of credit would also be under the Reimbursement Agreement rather than the Credit Agreement. As of March 31, 2015, the Company had $39.8 million in letters of credit outstanding.

Under the terms of the Reimbursement Agreement, the Company will reimburse Scotiabank on demand for any amounts that Scotiabank has disbursed under any letters of credit. Fees, charges and other reasonable expenses for the issuance of letters of credit are payable by the Company at the time of issuance at such rates and amounts as are in accordance with Scotiabank’s prevailing practice. The Company is obligated to pay to Scotiabank interest on all amounts not paid by the Company on the date of demand or when otherwise due at the LIBOR rate plus 2.25% per annum, calculated daily and payable monthly, in arrears, on the basis of a calendar year for the actual number of days elapsed, with interest on overdue interest at the same rate as on the reimbursement amounts.

The Company has also agreed that if obligations under the Credit Agreement are secured by liens on any of its or any of its subsidiaries’ property, then the Company’s reimbursement obligations and (to the extent similar obligations would be secured under the Credit Agreement) other obligations under the Reimbursement Agreement and any letters of credit will be equally and ratably secured by all property subject to such liens securing the Credit Agreement.

Pursuant to a Continuing Guaranty dated as of March 16, 2015 (the “Continuing Guaranty”), the Company’s payment obligations under the Reimbursement Agreement are jointly and severally guaranteed as to payment and not as to collection by subsidiaries of the Company that from time to time guarantee payment under the Credit Agreement.

On March 18, 2015, the Company entered into a Term Loan Agreement (the “2015 Term Loan Agreement”) with Wells Fargo Bank, N.A., as administrative agent and lender, each of the other lenders party thereto, Wells Fargo Securities, LLC, as Lead Arranger and Sole Book Runner, and Bank of America, N.A. and The Bank Of Tokyo-Mitsubishi UFJ, LTD., as Co-Syndication Agents.

The 2015 Term Loan Agreement is a senior unsecured single-advance term loan facility pursuant to which the Company made a term loan borrowing of $200 million on March 18, 2015 (the “Term Loan Borrowing”). The Term Loan Borrowing is payable in quarterly principal installments, together with accrued interest, on each June 30, September 30, December 31 and March 31, commencing on June 30, 2015. Each of the first four principal installments is in an amount equal to 2.5% of the Term Loan Borrowing and each successive quarterly installment, until and including June 30, 2017, is in an amount equal to 5.0% of the Term Loan Borrowing, with the outstanding principal balance of the Term Loan Borrowing due on the maturity date under the 2015 Term Loan Agreement. The maturity date under the 2015 Term Loan Agreement is September 27, 2017. Loans under the 2015 Term Loan Agreement bear interest, at the Company’s election, at the per annum rate of LIBOR rate plus 3.25% or base rate plus 2.25%.

Each domestic subsidiary of the Company will unconditionally guarantee all existing and future indebtedness and liabilities of the other guarantors and the Company arising under the 2015 Term Loan Agreement and other Loan Documents (as defined in the 2015 Term Loan Agreement), other than (a) Ambar Lone Star Fluid Services LLC, (b) domestic subsidiaries that directly or indirectly have no material assets other than equity interests in, or capitalization indebtedness owed by, foreign subsidiaries, and (c) any subsidiary having total assets of less than $1 million.

The 2015 Term Loan Agreement requires quarterly compliance with two financial covenants. The Company must not permit its debt to capitalization ratio to exceed 45%. The 2015 Term Loan Agreement generally defines the debt to capitalization ratio as the ratio of (a) total borrowed money indebtedness to (b) the sum of such indebtedness plus consolidated net worth, with consolidated net worth determined as of the most recently ended fiscal quarter. The Company also must not permit the interest coverage ratio as of the last day of a fiscal quarter to be less than 3.00 to 1.00. The 2015 Term Loan Agreement generally defines the interest coverage ratio as the ratio of EBITDA of the four prior fiscal quarters to interest charges for the same period.

The 2015 Term Loan Agreement further provides that neither the Company nor its subsidiaries is permitted to make restricted payments unless, after giving effect to such restricted payment, its pro forma ratio of debt to EBITDA for the four prior fiscal quarters, determined as of the preceding ending quarterly period, does not exceed 2.50 to 1.00. Restricted payments are generally defined as (a) dividends and distributions made on account of equity interests of the Company or its subsidiaries and (b) payments made to redeem, repurchase or otherwise retire equity interests of the Company or its subsidiaries. Payments made solely in the form of common equity interests, made to the Company and its subsidiaries, or made in connection with the Company’s long term incentive plans are not restricted payments under the 2015 Term Loan Agreement.

The 2015 Term Loan Agreement also contains customary representations, warranties, affirmative and negative covenants, and events of default. Events of default under the 2015 Term Loan Agreement include failure to pay principal or interest when due, failure to comply with the financial and operational covenants, as well as a cross default event, Loan Document enforceability event, change of control event and bankruptcy and other insolvency events. If an event of default occurs and is continuing, then a majority of the lenders have the right, among others, to accelerate and require the Company to repay all the outstanding amounts owed under any Loan Document (provided that in limited circumstances with respect to insolvency and bankruptcy of the Company, such acceleration is automatic).

Senior Notes — On October 5, 2010, the Company completed the issuance and sale of $300 million in aggregate principal amount of its 4.97% Series A Senior Notes due October 5, 2020 (the “Series A Notes”) in a private placement. The Series A Notes bear interest at a rate of 4.97% per annum. The Company will pay interest on the Series A Notes on April 5 and October 5 of each year. The Series A Notes will mature on October 5, 2020.

On June 14, 2012, the Company completed the issuance and sale of $300 million in aggregate principal amount of its 4.27% Series B Senior Notes due June 14, 2022 (the “Series B Notes”) in a private placement. The Series B Notes bear interest at a rate of 4.27% per annum. The Company will pay interest on the Series B Notes on April 5 and October 5 of each year. The Series B Notes will mature on June 14, 2022.

The Series A Notes and Series B Notes are senior unsecured obligations of the Company which rank equally in right of payment with all other unsubordinated indebtedness of the Company. The Series A Notes and Series B Notes are guaranteed on a senior unsecured basis by each of the existing domestic subsidiaries of the Company other than immaterial subsidiaries.

The Series A Notes and Series B Notes are prepayable at the Company’s option, in whole or in part, provided that in the case of a partial prepayment, prepayment must be in an amount not less than 5% of the aggregate principal amount of the notes then outstanding, at any time and from time to time at 100% of the principal amount prepaid, plus accrued and unpaid interest to the prepayment date, plus a “make-whole” premium as specified in the note purchase agreements. The Company must offer to prepay the notes upon the occurrence of any change of control. In addition, the Company must offer to prepay the notes upon the occurrence of certain asset dispositions if the proceeds therefrom are not timely reinvested in productive assets. If any offer to prepay is accepted, the purchase price of each prepaid note is 100% of the principal amount thereof, plus accrued and unpaid interest thereon to the prepayment date.

The respective note purchase agreements require compliance with two financial covenants. The Company must not permit its debt to capitalization ratio to exceed 50% at any time. The note purchase agreements generally define the debt to capitalization ratio as the ratio of (a) total borrowed money indebtedness to (b) the sum of such indebtedness plus consolidated net worth, with consolidated net worth determined as of the last day of the most recently ended fiscal quarter. The Company also must not permit the interest coverage ratio as of the last day of a fiscal quarter to be less than 2.50 to 1.00. The note purchase agreements generally define the interest coverage ratio as the ratio of EBITDA for the four prior fiscal quarters to interest charges for that same period. The Company was in compliance with these covenants at March 31, 2015.

Events of default under the note purchase agreements include failure to pay principal or interest when due, failure to comply with the financial and operational covenants, a cross default event, a judgment in excess of a threshold event, the guaranty agreement ceasing to be enforceable, the occurrence of certain ERISA events, a change of control event and bankruptcy and other insolvency events. If an event of default under the note purchase agreements occurs and is continuing, then holders of a majority in principal amount of the respective notes have the right to declare all the notes then-outstanding to be immediately due and payable. In addition, if the Company defaults in payments on any note, then until such defaults are cured, the holder thereof may declare all the notes held by it pursuant to the note purchase agreement to be immediately due and payable.

The Company incurred approximately $1.9 million in debt issuance costs during 2015 in connection with the Reimbursement Agreement and the 2015 Term Loan Agreement. Debt issuance costs are deferred and recognized as interest expense over the term of the underlying debt. Interest expense related to the amortization of debt issuance costs was approximately $547,000 for the three months ended March 31, 2015 and 2014, respectively.

Presented below is a schedule of the principal repayment requirements of long-term debt by fiscal year as of March 31, 2015 (in thousands):

As of March 31, 2015, the Company maintained letters of credit in the aggregate amount of $39.8 million for the benefit of various insurance companies as collateral for retrospective premiums and retained losses which could become payable under the terms of the underlying insurance contracts. These letters of credit expire annually at various times during the year and are typically renewed. As of March 31, 2015, no amounts had been drawn under the letters of credit.

As of March 31, 2015, the Company had commitments to purchase approximately $350 million of major equipment for its drilling and pressure pumping businesses.

The Company’s pressure pumping business has entered into agreements to purchase minimum quantities of proppants and chemicals from certain vendors. These agreements expire in 2016, 2017 and 2018. As of March 31, 2015, the remaining obligation under these agreements was approximately $69.3 million, of which materials with a total purchase price of approximately $13.0 million were required to be purchased during the remainder of 2015. In the event that the required minimum quantities are not purchased during any contract year, the Company could be required to make a liquidated damages payment to the respective vendor for any shortfall.

In November 2011, the Company’s pressure pumping business entered into an agreement with a proppant vendor to advance up to $12.0 million to such vendor to finance the construction of certain processing facilities. This advance is secured by the underlying processing facilities and bears interest at an annual rate of 5.0%. Repayment of the advance is to be made through discounts applied to purchases from the vendor and repayment of all amounts advanced must be made no later than October 1, 2017. As of March 31, 2015, advances of approximately $11.8 million had been made under this agreement and principal repayments of approximately $9.7 million had been received resulting in a balance outstanding of approximately $2.1 million.

In May 2013, the U.S. Equal Employment Opportunity Commission (“EEOC”) notified the Company of cause findings related to certain employment practices of its U.S. drilling subsidiary. In March 2015, the EEOC filed a lawsuit, and on the same day the EEOC and the subsidiary filed a consent decree agreeing to settle the lawsuit on a no-fault basis and requiring the subsidiary to pay $12.26 million into a settlement fund for eligible participants. On April 17, 2015, a Federal court judge approved and signed the consent decree, which resolved the allegations in the lawsuit that the subsidiary engaged in a pattern or practice of nationwide discrimination based on race, color, and/or national origin in three respects: (i) creating and/or tolerating a hostile work environment, (ii) disparate treatment in terms and conditions of employment and (iii) retaliation.

In October 2014, the Company was notified by EPA Region 6 that it intended to seek civil penalties for alleged RCRA administrative violations at a former facility of one of the Company’s subsidiaries in Midland, Texas. The EPA subsequently alleged RCRA administrative violations at other facilities of that subsidiary. EPA sought an aggregate monetary penalty of approximately $1.1 million. In late March 2015, the Company completed negotiations with the EPA and an Order was entered in April 2015 imposing a penalty of approximately $500,000 to resolve the alleged RCRA issues at certain current and former facilities. The Order also requires the subsidiary to assess its ongoing compliance status and address any deficiencies.

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

Cash Dividends — The Company paid cash dividends during the three months ended March 31, 2014 and 2015 as follows:

On April 22, 2015, the Company’s Board of Directors approved a cash dividend on its common stock in the amount of $0.10 per share to be paid on June 24, 2015 to holders of record as of June 10, 2015. The amount and timing of all future dividend payments, if any, are subject to the discretion of the Board of Directors and will depend upon business conditions, results of operations, financial condition, terms of the Company’s credit facilities and other factors.

On September 6, 2013, the Company’s Board of Directors approved a stock buyback program that authorizes purchase of up to $200 million of the Company’s common stock in open market or privately negotiated transactions. As of March 31, 2015, the Company had remaining authorization to purchase approximately $187 million of the Company’s outstanding common stock under the stock buyback program. Shares purchased under a buyback program are accounted for as treasury stock.

There were no acquisitions of treasury stock during the three months ended March 31, 2015.

The Company’s effective income tax rate was 42.4% for the three months ended March 31, 2015, compared to 32.7% for the three months ended March 31, 2014. The Domestic Production Activities Deduction was enacted as part of the American Jobs Creation Act of 2004 (as revised by the Emergency Economic Stabilization Act of 2008), and allows a deduction of 9% on the lesser of qualified production activities income or taxable income. For financial statement purposes, the Company expects a loss before income taxes for the year ending December 31, 2015; however, the Company currently expects to have taxable income for the year ending December 31, 2015, and the Domestic Production Activities Deduction is expected to provide a permanent tax benefit. The interplay between the expected loss before income taxes for financial statement purposes and the permanent tax benefit expected to be provided by the Domestic Production Activities Deduction results in a higher effective income tax rate for the three months ended March 31, 2015.

The carrying values of cash and cash equivalents, trade receivables and accounts payable approximate fair value due to the short-term maturity of these items. These fair value estimates are considered Level 1 fair value estimates in the fair value hierarchy of fair value accounting.

The estimated fair value of the Company’s outstanding debt balances (including current portion) as of March 31, 2015 and December 31, 2014 is set forth below (in thousands):

	March 31, 2015				December 31, 2014
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value
Borrowings under Credit Agreement:
Revolving credit facility	$	—	$	—	$	303,000	$	303,000
Term loan facility		80,000		80,000		82,500		82,500
2015 Term Loan		200,000		200,000		—		—
4.97% Series A Senior Notes		300,000		312,668		300,000		288,346
4.27% Series B Senior Notes		300,000		298,137		300,000		269,173
Total debt	$	880,000	$	890,805	$	985,500	$	943,019

The carrying values of the balances outstanding under the Credit Agreement and the 2015 Term Loan Agreement approximate their fair values as these instruments have a floating interest rate. The fair value of the Series A Notes and the Series B Notes at March 31, 2015 and December 31, 2014 are based on discounted cash flows associated with the respective notes using current market rates of interest at those respective dates. For the Series A Notes, the current market rates used in measuring this fair value were 4.11% at March 31, 2015 and 5.77% at December 31, 2014. For the Series B Notes, the current market rates used in measuring this fair value were 4.37% at March 31, 2015 and 6.00% at December 31, 2014. These fair value estimates are based on observable market inputs and are considered Level 2 fair value estimates in the fair value hierarchy of fair value accounting.

In May 2014, the FASB issued an accounting standards update to provide guidance on the recognition of revenue from customers. Under this guidance, an entity will recognize revenue when it transfers promised goods or services to customers in an amount that reflects what it expects in exchange for the goods or services. This guidance also requires more detailed disclosures to enable users of the financial statements to understand the nature, amount, timing and uncertainty, if any, of revenue and cash flows arising from contracts with customers. The requirements in this update are effective during interim and annual periods beginning after December 15, 2017. The Company is currently evaluating the impact this guidance will have on its consolidated financial statements.

In June 2014, the FASB issued an accounting standards update to provide guidance on the accounting for share-based payments when the terms of an award provide that a performance target could be achieved after the requisite service period. The guidance requires that a performance target that affects vesting and that could be achieved after the requisite service period is treated as a performance condition. The requirements in this update are effective during interim and annual periods beginning after December 15, 2015. The adoption of this update is not expected to have a material impact on the Company’s consolidated financial statements.

This Quarterly Report on Form 10-Q (this “Report”) and other public filings and press releases by us contain “forward-looking statements” within the meaning of the Securities Act of 1933, as amended (the “Securities Act”), the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and the Private Securities Litigation Reform Act of 1995, as amended. These “forward-looking statements” involve risk and uncertainty. These forward-looking statements include, without limitation, statements relating to: liquidity; revenue and cost expectations and backlog; financing of operations; oil and natural gas prices; source and sufficiency of funds required for building new equipment and additional acquisitions (if further opportunities arise); impact of inflation; demand for our services; competition; equipment availability; government regulation; and other matters. Our forward-looking statements can be identified by the fact that they do not relate strictly to historical or current facts and often use words such as “anticipates,” “believes,” “budgeted,” “continue,” “could,” “estimates,” “expects,” “intends,” “may,” “plans,” “project,” “strategy,” or “will,” or the negative thereof and other words and expressions of similar meaning. The forward-looking statements are based on certain assumptions and analyses we make in light of our experience and our perception of historical trends, current conditions, expected future developments and other factors we believe are appropriate in the circumstances. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we can give no assurance that such expectations will prove to have been correct. Forward-looking statements may be made orally or in writing, including, but not limited to, Management’s Discussion and Analysis of Financial Condition and Results of Operations included in this Report and other sections of our filings with the United States Securities and Exchange Commission (the “SEC”) under the Exchange Act and the Securities Act.

Forward-looking statements are not guarantees of future performance and a variety of factors could cause actual results to differ materially from the anticipated or expected results expressed in or suggested by these forward-looking statements. Factors that might cause or contribute to such differences include, but are not limited to, volatility in customer spending and in oil and natural gas prices that could adversely affect demand for our services and their associated effect on rates, utilization, margins and planned capital expenditures, global economic conditions, excess availability of land drilling rigs and pressure pumping equipment, including as a result of reactivation or construction, equipment specialization and new technologies, adverse industry conditions, adverse credit and equity market conditions, difficulty in building and deploying new equipment and integrating acquisitions, shortages, delays in delivery and interruptions in supply of equipment, supplies and materials, weather, loss of key customers, liabilities from operations for which we do not have and receive full indemnification or insurance, ability to effectively identify and enter new markets, governmental regulation, ability to realize backlog, ability to retain management and field personnel and other factors. Refer to “Risk Factors” contained in Part 1 of our Annual Report on Form 10-K for the year ended December 31, 2014 for a more complete discussion of factors that might affect our performance and financial results. You are cautioned not to place undue reliance on any of our forward-looking statements. These forward-looking statements are intended to relay our expectations about the future, and speak only as of the date they are made. We undertake no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, changes in internal estimates or otherwise, except as required by law.

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

Recent Developments — Oil prices declined significantly during the second half of 2014 and have continued to decline in early 2015. The closing price of oil was as high as $105.68 per barrel during the third quarter of 2014, and reached a multi-year low of $43.39 on March 17, 2015 (WTI spot price as reported by the United States Energy Information Administration). As a result of the decline in oil prices, our industry is now experiencing a severe downturn. Market conditions remain very dynamic and are changing quickly. Although the magnitude as well as the duration of this downturn are not yet known, we believe that 2015 will continue to be a challenging year for our industry.

We believe the vast majority of exploration and production companies, including our customers, have significantly reduced their 2015 capital spending plans. The impact of these spending reductions is evidenced by the published rig counts, which have declined by approximately 50% in the United States since the recent peak in October 2014.

Our rig count has also declined. During October 2014, the number of our drilling rigs operating in the United States was as high as 214, and as of April 23, 2015 we had 126 drilling rigs operating in the United States. We have received indications of customers’ intent to early terminate a number of term contracts and many of our drilling customers are continuing to seek price reductions. We expect the number of our drilling rigs operating in the United States to continue to decline during the second quarter of 2015.

Our pressure pumping business is also experiencing the effects of reduced spending by customers. Some previously scheduled pressure pumping jobs have been cancelled or deferred and many customers are also seeking price reductions.

In anticipation of this downturn, we began reducing our cost structure in the fourth quarter of 2014. In 2015, we have continued to reduce our cost structure and, to date, we have reduced our drilling headcount at a rate proportionate with the reduction in our rig count. We have also reduced our capital expenditure plans for 2015. Along with other reductions, we plan to only build new drilling rigs that are currently committed under term contracts. We plan to continue to adjust our cost structure in line with our level of operating activity.

We expect that our term contract coverage and scalability with respect to labor and other operating costs should position us to weather this downturn. We expect to experience further declines in both drilling activity and spot dayrate pricing, and in pressure pumping activity and pricing. In the event oil prices remain depressed for a sustained period, or decline further, these declines could have a material adverse effect on our business, financial condition and results of operations.

Management Overview — We are a leading provider of services to the North American oil and natural gas industry. Our services primarily involve the drilling, on a contract basis, of land-based oil and natural gas wells and pressure pumping services. In addition to these services, we also invest, on a non-operating working interest basis, in oil and natural gas properties.

We operate land-based drilling rigs in oil and natural gas producing regions of the continental United States and western Canada. There continues to be uncertainty with respect to the global economic environment, and crude oil and natural gas prices are depressed. During the first quarter of 2015, our average number of rigs operating in the United States was 165 compared to an average of 193 drilling rigs operating during the same period in 2014. During the first quarter of 2015, our average number of rigs operating in Canada was 8 compared to an average of 10 drilling rigs operating during the first quarter of 2014.

We have addressed our customers’ needs for drilling horizontal wells in shale and other unconventional resource plays by expanding our areas of operation and improving the capabilities of our drilling fleet during the last several years. As of March 31, 2015, we had completed 151 APEX^® rigs. We have plans to complete 10 additional new APEX^® rigs during the three quarters ending December 2015.

In connection with horizontal shale and other unconventional resource plays, we have added equipment to perform service intensive fracturing jobs. As of March 31, 2015, we had approximately 1.1 million hydraulic horsepower in our pressure pumping fleet. We have increased the horsepower of our pressure pumping fleet by more than eight-fold since the beginning of 2009. In recent years, low natural gas prices and the industry-wide addition of new pressure pumping equipment to the marketplace led to an excess supply of pressure pumping equipment in North America.

We maintain a backlog of commitments for contract drilling revenues under term contracts, which we define as contracts with a fixed term of six months or more. Our backlog as of March 31, 2015 was approximately $1.24 billion. We expect approximately $622 million of our backlog to be realized in the remainder of 2015. We generally calculate our backlog by multiplying the dayrate under our term drilling contracts by the number of days remaining under the contract. The calculation does not include any revenues related to other fees such as for mobilization, demobilization and customer reimbursables, nor does it include potential reductions in rates for unscheduled standby or during periods in which the rig is moving or incurring maintenance and repair time in excess of what is permitted under the drilling contract. In addition, generally our term drilling contracts are subject to termination by the customer on short notice and provide for an early termination payment to us in the event that the contract is terminated by the customer. For contracts that we have received an early termination notice, our backlog calculation includes the early termination rate, instead of the day rate, for the period we expect to receive the lower rate.

For the three months ended March 31, 2015 and 2014, our operating revenues consisted of the following (in thousands):

Generally, the profitability of our business is impacted most by two primary factors in our contract drilling segment: our average number of rigs operating and our average revenue per operating day. During the first quarter of 2015, our average number of rigs operating was 165 in the United States and 8 in Canada compared to 193 in the United States and 10 in Canada in the first quarter of 2014. Our average revenue per operating day was $25,870 in the first quarter of 2015, including $15.8 million of early termination revenue, compared to $23,380 in the first quarter of 2014. Consolidated net income for the first quarter of 2015 was $9.1 million compared to consolidated net income of $34.8 million for the first quarter of 2014. This decrease in consolidated net income is primarily due to higher depreciation expense related to capital expenditures and acquisitions.

Our revenues, profitability and cash flows are highly dependent upon prevailing prices for oil and natural gas. During periods of improved commodity prices, the capital spending budgets of oil and natural gas operators tend to expand, which generally results in increased demand for our services. Conversely, in periods when these commodity prices deteriorate, the demand for our services generally weakens, and we experience downward pressure on pricing for our services. In March 2015, our average number of rigs operating was 142 in the United States and 4 in Canada.

We are highly impacted by operational risks, competition, the availability of excess equipment, labor issues, weather and various other factors that could materially adversely affect our business, financial condition, cash flows and results of operations. Please see “Risk Factors” included in Part I of our Annual Report on Form 10-K for the fiscal year ended December 31, 2014.

Our liquidity as of March 31, 2015 included approximately $127 million in working capital and almost $500 million available under our revolving credit facility. We believe our current liquidity, together with cash expected to be generated from operations, should provide us with sufficient ability to fund our current plans to build new equipment, make improvements to our existing equipment, service our debt and pay cash dividends. If we pursue opportunities for growth that require capital, we believe we would be able to satisfy the needs through a combination of working capital, cash flows from operating activities, borrowing capacity under our revolving credit facility, debt financing and equity financing. However, there can be no assurance that such capital will be available on reasonable terms, if at all.

Commitments and Contingencies — As of March 31, 2015, we maintained letters of credit in the aggregate amount of $39.8 million for the benefit of various insurance companies as collateral for retrospective premiums and retained losses which could become payable under the terms of the underlying insurance contracts. These letters of credit expire annually at various times during the year and are typically renewed. As of March 31, 2015, no amounts had been drawn under the letters of credit.

As of March 31, 2015, we had commitments to purchase approximately $350 million of major equipment for our drilling and pressure pumping businesses.

Our pressure pumping business has entered into agreements to purchase minimum quantities of proppants and chemicals from certain vendors. These agreements expire in 2016, 2017 and 2018. As of March 31, 2015, the remaining obligation under these agreements was approximately $69.3 million, of which materials with a total purchase price of approximately $13.0 million were required to be purchased during the remainder of 2015. In the event that the required minimum quantities are not purchased during any contract year, we could be required to make a liquidated damages payment to the respective vendor for any shortfall.

In November 2011, our pressure pumping business entered into an agreement with a proppant vendor to advance up to $12.0 million to such vendor to finance its construction of certain processing facilities. This advance is secured by the underlying processing facilities and bears interest at an annual rate of 5.0%. Repayment of the advance is to be made through discounts applied to purchases from the vendor and repayment of all amounts advanced must be made no later than October 1, 2017. As of March 31, 2015, advances of approximately $11.8 million had been made under this agreement and repayments of approximately $9.7 million had been received resulting in a balance outstanding of approximately $2.1 million.

In May 2013, the EEOC notified us of cause findings related to certain employment practices of our U.S. drilling subsidiary. In March 2015, the EEOC filed a lawsuit, and on the same day the EEOC and our subsidiary filed a consent decree agreeing to settle the lawsuit on a no-fault basis and requiring the subsidiary to pay $12.26 million into a settlement fund for eligible participants. On April 17, 2015, a Federal court judge approved and signed the consent decree, which resolved the allegations in the lawsuit that our subsidiary engaged in a pattern or practice of nationwide discrimination based on race, color, and/or national origin in three respects: (i) creating and/or tolerating a hostile work environment, (ii) disparate treatment in terms and conditions of employment and (iii) retaliation.

In October 2014, we were notified by EPA region 6 that it intended to seek civil penalties for alleged RCRA administrative violations at a former facility of one of our subsidiaries in Midland, Texas. The EPA subsequently alleged RCRA administrative violations at other facilities of that subsidiary. EPA sought an aggregate monetary penalty of approximately $1.1 million. In late March 2015, we completed negotiations with the EPA and an Order was entered in April 2015 imposing a penalty of approximately $500,000 to resolve the alleged RCRA issues at certain current and former facilities. The Order also requires the subsidiary to assess its ongoing compliance status and address any deficiencies.

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

Description of Business — We conduct our contract drilling operations primarily in the continental United States and western Canada. We provide pressure pumping services to oil and natural gas operators primarily in Texas and the Appalachian region. Pressure pumping services are primarily well stimulation and cementing for completion of new wells and remedial work on existing wells. We also invest in oil and natural gas assets as a non-operating working interest owner. Our oil and natural gas working interests are located primarily in Texas and New Mexico.

The North American oil and natural gas services industry is cyclical and at times experiences downturns in demand. During these periods, there have been substantially more drilling rigs and pressure pumping equipment available than necessary to meet demand. As a result, drilling and pressure pumping contractors have had difficulty sustaining profit margins and, at times, have incurred losses during the downturn periods.

Construction of new technology drilling rigs has increased in recent years. The addition of new technology drilling rigs to the market, combined with a reduction in the drilling of vertical wells, has resulted in excess capacity of older technology drilling rigs. Similarly, the substantial increase in unconventional resource plays has led to higher demand for pressure pumping services, and there has been a significant increase in the construction of new pressure pumping equipment across the industry. As a result of relatively low oil and natural gas prices and the construction of new equipment, there has been an excess of pressure pumping equipment available. In circumstances of excess capacity, providers of pressure pumping services have difficulty sustaining profit margins and may sustain losses during downturn periods. We cannot predict either the future level of demand for our contract drilling or pressure pumping services or future conditions in the oil and natural gas contract drilling or pressure pumping businesses.

In addition, unconventional resource plays have substantially increased and some drilling rigs are not capable of drilling these wells efficiently. Accordingly, the utilization of some older technology drilling rigs has been hampered by their lack of capability to efficiently compete for this work. Other ongoing factors which could continue to adversely affect utilization rates and pricing, even in an environment of high oil and natural gas prices and increased drilling activity, include:

In addition to established accounting policies, our consolidated condensed financial statements are impacted by certain estimates and assumptions made by management. No changes in our critical accounting policies have occurred since the filing of our Annual Report on Form 10-K for the fiscal year ended December 31, 2014.

Our liquidity as of March 31, 2015 included approximately $127 million in working capital and almost $500 million available under our revolving credit facility. We believe our current liquidity, together with cash expected to be generated from operations, should provide us with sufficient ability to fund our current plans to build new equipment, make improvements to our existing equipment, service our debt and pay cash dividends. If we pursue opportunities for growth that require capital, we believe we would be able to satisfy these needs through a combination of working capital, cash flows from operating activities, borrowing capacity under our revolving credit facility, debt financing and equity financing. However, there can be no assurance that such capital will be available on reasonable terms, if at all.

During the three months ended March 31, 2015, our sources of cash flow included:

During the three months ended March 31, 2015, we used a net of $303 million to pay off our revolving credit facility, $14.6 million to pay dividends on our common stock, $2.5 million to repay long-term debt, $1.9 million to pay debt issuance costs and $241.5 million:

On April 22, 2015, our Board of Directors approved a cash dividend on our common stock in the amount of $0.10 per share to be paid on June 24, 2015 to holders of record as of June 10, 2015. The amount and timing of all future dividend payments, if any, is subject to the discretion of the Board of Directors and will depend upon business conditions, results of operations, financial condition, terms of our credit facilities and other factors.

On September 6, 2013, our Board of Directors approved a stock buyback program that authorizes purchase of up to $200 million of our common stock in open market or privately negotiated transactions. As of March 31, 2015, we had remaining authorization to purchase approximately $187 million of our outstanding common stock under the stock buyback program. Shares purchased under a buyback program are accounted for as treasury stock.

There were no treasury stock acquisitions during the three months ended March 31, 2015.

On September 27, 2012, we entered into a Credit Agreement (as amended, the “Credit Agreement”). The Credit Agreement is a committed senior unsecured credit facility that includes a revolving credit facility and a term loan facility.

Subject to customary conditions, we may request that the lenders’ aggregate commitments with respect to the revolving credit facility and/or the term loan facility be increased by up to $100 million, not to exceed total commitments of $700 million. The maturity date under the Credit Agreement is September 27, 2017 for both the revolving facility and the term facility.

Loans under the Credit Agreement bear interest by reference, at our election, to the LIBOR rate or base rate, provided, that swing line loans bear interest by reference only to the base rate. The applicable margin on LIBOR rate loans varies from 2.25% to 3.25% and the applicable margin on base rate loans varies from 1.25% to 2.25%, in each case determined based upon our debt to capitalization ratio. As of March 31, 2015, the applicable margin on LIBOR rate loans was 2.25% and the applicable margin on base rate loans was 1.25%. Based on our debt to capitalization ratio at December 31, 2014, the applicable margin on LIBOR loans is 2.75% and the applicable margin on base rate loans is 1.75% as of April 1, 2015. Based on our debt to capitalization ratio at March 31, 2015, the applicable margin on LIBOR loans will be 2.25% and the applicable margin on base rate loans will be 1.25% as of July 1, 2015. A letter of credit fee is payable by us equal to the applicable margin for LIBOR rate loans times the daily amount available to be drawn under outstanding letters of credit. The commitment fee rate payable to the lenders for the unused portion of the credit facility is 0.50%.

Each of our domestic subsidiaries will unconditionally guarantee all existing and future indebtedness and liabilities of the other guarantors and us arising under the Credit Agreement, other than (a) Ambar Lone Star Fluid Services LLC, (b) domestic subsidiaries that directly or indirectly have no material assets other than equity interests in, or capitalization indebtedness owed by, foreign subsidiaries, and (c) any subsidiary having total assets of less than $1 million. Such guarantees also cover our obligations and those of any of our subsidiaries arising under any interest rate swap contract with any person while such person is a lender or an affiliate of a lender under the Credit Agreement.

The Credit Agreement requires compliance with two financial covenants. We must not permit our debt to capitalization ratio to exceed 45%. The Credit Agreement generally defines the debt to capitalization ratio as the ratio of (a) total borrowed money indebtedness to (b) the sum of such indebtedness plus consolidated net worth, with consolidated net worth determined as of the last day of the most recently ended fiscal quarter. We also must not permit the interest coverage ratio as of the last day of a fiscal quarter to be less than 3.00 to 1.00. The Credit Agreement generally defines the interest coverage ratio as the ratio of EBITDA of the four prior fiscal quarters to interest charges for the same period. We were in compliance with these financial covenants as of March 31, 2015. The Credit Agreement also contains customary representations, warranties and affirmative and negative covenants. We do not expect that the restrictions and covenants will impair, in any material respect, our ability to operate or react to opportunities that might arise.

Events of default under the Credit Agreement include failure to pay principal or interest when due, failure to comply with the financial and operational covenants, as well as a cross default event, loan document enforceability event, change of control event and bankruptcy and other insolvency events. If an event of default occurs and is continuing, then a majority of the lenders have the right, among others, to (i) terminate the commitments under the Credit Agreement, (ii) accelerate and require us to repay all the outstanding amounts owed under any loan document (provided that in limited circumstances with respect to insolvency and bankruptcy, such acceleration is automatic), and (iii) require us to cash collateralize any outstanding letters of credit.

As of March 31, 2015, we had $80.0 million principal amount outstanding under the term loan facility at an interest rate of 2.625% and no amounts outstanding under the revolving credit facility. The $39.8 million in letters of credit previously outstanding under the Credit Agreement have been replaced as discussed below and, as a result, we currently have available borrowing capacity of $500 million.

On March 16, 2015, we entered into a Reimbursement Agreement (the “Reimbursement Agreement”) with The Bank of Nova Scotia (“Scotiabank”), pursuant to which we may from time to time request that Scotiabank issue an unspecified amount of letters of credit. The letters of credit previously outstanding under the Credit Agreement have been replaced by letters of credit issued under the Reimbursement Agreement. We expect that any future requests for letters of credit would also be under the Reimbursement Agreement rather than the Credit Agreement. As of March 31, 2015, we had $39.8 million in letters of credit outstanding.

Under the terms of the Reimbursement Agreement, we will reimburse Scotiabank on demand for any amounts that Scotiabank has disbursed under any letters of credit. Fees, charges and other reasonable expenses for the issuance of letters of credit are payable by us at the time of issuance at such rates and amounts as are in accordance with Scotiabank’s prevailing practice. We are obligated to pay to Scotiabank interest on all amounts not paid on the date of demand or when otherwise due at the LIBOR rate plus 2.25% per annum, calculated daily and payable monthly, in arrears, on the basis of a calendar year for the actual number of days elapsed, with interest on overdue interest at the same rate as on the reimbursement amounts.

We have also agreed that if obligations under the Credit Agreement are secured by liens on any of our subsidiaries’ property, then our reimbursement obligations and (to the extent similar obligations would be secured under the Credit Agreement) other obligations under the Reimbursement Agreement and any letters of credit will be equally and ratably secured by all property subject to such liens securing the Credit Agreement.

Pursuant to a Continuing Guaranty dated as of March 16, 2015 (the “Continuing Guaranty”), our payment obligations under the Reimbursement Agreement are jointly and severally guaranteed as to payment and not as to collection by our subsidiaries that from time to time guarantee payment under the Credit Agreement.

On March 18, 2015, we entered into a Term Loan Agreement (the “2015 Term Loan Agreement”) with Wells Fargo Bank, N.A., as administrative agent and lender, each of the other lenders party thereto, Wells Fargo Securities, LLC, as Lead Arranger and Sole Book Runner, and Bank of America, N.A. and The Bank Of Tokyo-Mitsubishi UFJ, LTD., as Co-Syndication Agents.

The 2015 Term Loan Agreement is a senior unsecured single-advance term loan facility pursuant to which we made a term loan borrowing of $200 million on March 18, 2015 (the “Term Loan Borrowing”). The Term Loan Borrowing is payable in quarterly principal installments, together with accrued interest, on each June 30, September 30, December 31 and March 31, commencing on June 30, 2015. Each of the first four principal installments is in an amount equal to 2.5% of the Term Loan Borrowing and each successive quarterly installment, until and including June 30, 2017, is in an amount equal to 5.0% of the Term Loan Borrowing, with the outstanding principal balance of the Term Loan Borrowing due on the maturity date under the 2015 Term Loan Agreement. The maturity date under the 2015 Term Loan Agreement is September 27, 2017. Loans under the 2015 Term Loan Agreement bear interest, at our election, at the per annum rate of LIBOR rate plus 3.25% or base rate plus 2.25%.

Each of our domestic subsidiaries will unconditionally guarantee all existing and future indebtedness and liabilities of the other guarantors and us arising under the 2015 Term Loan Agreement and other Loan Documents (as defined in the 2015 Term Loan Agreement), other than (a) Ambar Lone Star Fluid Services LLC, (b) domestic subsidiaries that directly or indirectly have no material assets other than equity interests in, or capitalization indebtedness owed by, foreign subsidiaries, and (c) any subsidiary having total assets of less than $1 million.

The 2015 Term Loan Agreement requires quarterly compliance with two financial covenants. We must not permit our debt to capitalization ratio to exceed 45%. The 2015 Term Loan Agreement generally defines the debt to capitalization ratio as the ratio of (a) total borrowed money indebtedness to (b) the sum of such indebtedness plus consolidated net worth, with consolidated net worth determined as of the most recently ended fiscal quarter. We also must not permit the interest coverage ratio as of the last day of a fiscal quarter to be less than 3.00 to 1.00. The 2015 Term Loan Agreement generally defines the interest coverage ratio as the ratio of EBITDA of the four prior fiscal quarters to interest charges for the same period. We were in compliance with these financial covenants as of March 31, 2015.

The 2015 Term Loan Agreement further provides that neither by us nor our subsidiaries is permitted to make restricted payments unless, after giving effect to such restricted payment, its pro forma ratio of debt to EBITDA for the four prior fiscal quarters, determined as of the preceding ending quarterly period, does not exceed 2.50 to 1.00. Restricted payments are generally defined as (a) dividends and distributions made on account of our equity interests or our subsidiaries and (b) payments made to redeem, repurchase or otherwise retire our equity interests or our subsidiaries. Payments made solely in the form of common equity interests, made to us and our subsidiaries, or made in connection with the our long term incentive plans are not restricted payments under the 2015 Term Loan Agreement.

The 2015 Term Loan Agreement also contains customary representations, warranties, affirmative and negative covenants, and events of default. Events of default under the 2015 Term Loan Agreement include failure to pay principal or interest when due, failure to comply with the financial and operational covenants, as well as a cross default event, Loan Document enforceability event, change of control event and bankruptcy and other insolvency events. If an event of default occurs and is continuing, then a majority of the lenders have the right, among others, to accelerate and require us to repay all the outstanding amounts owed under any Loan Document (provided that in limited circumstances with respect to insolvency and bankruptcy, such acceleration is automatic).

On October 5, 2010, we completed the issuance and sale of $300 million in aggregate principal amount of our 4.97% Series A Senior Notes due October 5, 2020 (the “Series A Notes”) in a private placement. The Series A Notes bear interest at a rate of 4.97% per annum. We pay interest on the Series A Notes on April 5 and October 5 of each year. The Series A Notes will mature on October 5, 2020.

On June 14, 2012, we completed the issuance and sale of $300 million in aggregate principal amount of our 4.27% Series B Senior Notes due June 14, 2022 (the “Series B Notes”) in a private placement. The Series B Notes bear interest at a rate of 4.27% per annum. We pay interest on the Series B Notes on April 5 and October 5 of each year. The Series B Notes will mature on June 14, 2022.

The Series A Notes and Series B Notes are senior unsecured obligations which rank equally in right of payment with all of our other unsubordinated indebtedness. The Series A Notes and Series B Notes are guaranteed on a senior unsecured basis by each of our existing domestic subsidiaries other than immaterial subsidiaries.

The Series A Notes and Series B Notes are prepayable at our option, in whole or in part, provided that in the case of a partial prepayment, prepayment must be in an amount not less than 5% of the aggregate principal amount of the notes then outstanding, at any time and from time to time at 100% of the principal amount prepaid, plus accrued and unpaid interest to the prepayment date, plus a “make-whole” premium as specified in the note purchase agreements. We must offer to prepay the notes upon the occurrence of any change of control. In addition, we must offer to prepay the notes upon the occurrence of certain asset dispositions if the proceeds therefrom are not timely reinvested in productive assets. If any offer to prepay is accepted, the purchase price of each prepaid note is 100% of the principal amount thereof, plus accrued and unpaid interest thereon to the prepayment date.

The respective note purchase agreements require compliance with two financial covenants. We must not permit our debt to capitalization ratio to exceed 50% at any time. The note purchase agreements generally define the debt to capitalization ratio as the ratio of (a) total borrowed money indebtedness to (b) the sum of such indebtedness plus consolidated net worth, with consolidated net worth determined as of the last day of the most recently ended fiscal quarter. We also must not permit the interest coverage ratio as of the last day of a fiscal quarter to be less than 2.50 to 1.00. The note purchase agreements generally define the interest coverage ratio as the ratio of EBITDA for the four prior fiscal quarters to interest charges for the same period. We were in compliance with these financial covenants as of March 31, 2015. We do not expect that the restrictions and covenants will impair, in any material respect, our ability to operate or react to opportunities that might arise.

Events of default under the note purchase agreements include failure to pay principal or interest when due, failure to comply with the financial and operational covenants, a cross default event, a judgment in excess of a threshold event, the guaranty agreement ceasing to be enforceable, the occurrence of certain ERISA events, a change of control event and bankruptcy and other insolvency events. If an event of default under the note purchase agreements occurs and is continuing, then holders of a majority in principal amount of the respective notes have the right to declare all the notes then-outstanding to be immediately due and payable. In addition, if we default in payments on any note, then until such defaults are cured, the holder thereof may declare all the notes held by it pursuant to the note purchase agreement to be immediately due and payable.

Our liquidity as of March 31, 2015 included approximately $127 million in working capital and almost $500 million available under our revolving credit facility. We believe our current liquidity together with cash expected to be generated from operations, should provide us with sufficient ability to fund our current plans to build new equipment, make improvements to our existing equipment, service our debt and pay cash dividends. If we pursue opportunities for growth that require capital, we believe we would be able to satisfy these needs through a combination of working capital, cash flows from operating activities, borrowing capacity under our revolving credit facility, debt financing and equity financing. However, there can be no assurance that such capital will be available on reasonable terms, if at all.

The following tables summarize operations by business segment for the three months ended March 31, 2015 and 2014:

Contract Drilling	2015		2014		% Change
	(Dollars in thousands)
Revenues	$	401,478	$	425,903		(5.7	)%
Direct operating costs		212,810		251,059		(15.2	)%
Margin (1)		188,668		174,844		7.9	%
Selling, general and administrative		13,698		1,648		731.2	%
Depreciation, amortization and impairment		118,832		106,119		12.0	%
Operating income	$	56,138	$	67,077		(16.3	)%
Operating days		15,520		18,214		(14.8	)%
Average revenue per operating day	$	25.87	$	23.38		10.7	%
Average direct operating costs per operating day	$	13.71	$	13.78		(0.5	)%
Average margin per operating day (1)	$	12.16	$	9.60		26.7	%
Average rigs operating		172		202		(14.9	)%
Capital expenditures	$	157,422	$	124,923		26.0	%

The decreases in revenues and direct operating costs reflect the decrease in the number of rigs operating. Average revenue per operating day and average margin per operating day were higher in 2015 due to higher average dayrates and the early termination revenues of approximately $15.8 million. Selling, general and administrative expense for 2015 includes a $12.3 million charge related to our settlement with the EEOC. The increase in depreciation expense reflects significant capital expenditures incurred in recent years to add new rigs to the fleet. Capital expenditures were incurred in recent years to build new drilling rigs, to modify and upgrade

existing drilling rigs and to acquire additional related equipment such as top drives, drill pipe, drill collars, engines, fluid circulating systems, rig hoisting systems and safety enhancement equipment.

Pressure Pumping	2015			2014			% Change
	(Dollars in thousands)
Revenues	$	249,721		$	240,261			3.9	%
Direct operating costs		212,725			199,808			6.5	%
Margin (1)		36,996			40,453			(8.5	)%
Selling, general and administrative		5,093			4,868			4.6	%
Depreciation, amortization and impairment		46,919			34,042			37.8	%
Operating income	$	(15,016	)	$	1,543			(1,073.2	)%
Fracturing jobs		216			243			(11.1	)%
Other jobs		618			880			(29.8	)%
Total jobs		834			1,123			(25.7	)%
Average revenue per fracturing job	$	1,097.87		$	914.73			20.0	%
Average revenue per other job	$	20.36		$	20.43			(0.3	)%
Average revenue per total job	$	299.43		$	213.95			40.0	%
Average direct operating costs per total job	$	255.07		$	177.92			43.4	%
Average margin per total job (1)	$	44.36		$	36.02			23.2	%
Margin as a percentage of revenues (1)		14.8	%		16.8	%		(11.9	)%
Capital expenditures and acquisitions	$	75,811		$	36,297			108.9	%

Revenues and direct operating costs increased due to an increase in the size of our jobs. Our customers have continued the development of unconventional reservoirs resulting in an increase in the proportion of larger multi-stage fracturing jobs associated therewith. In connection with the horizontal shale and other unconventional resource plays, we have added equipment to perform service intensive fracturing jobs including two acquisitions in 2014 of Texas-based pressure pumping operations. As a result, these larger multi-stage fracturing jobs are a larger proportion of the total fracturing jobs we performed. Additionally, the average size of the multi-stage fracturing jobs has increased. Average revenue per fracturing job and average direct operating costs per total job increased as a result of this increase in the proportion of larger multi-stage fracturing jobs and the increased size of the jobs in 2015 as compared to 2014. However, the total number of jobs decreased reflecting the downturn in the oil and natural gas industry. Depreciation expense increased due to capital expenditures.

Oil and Natural Gas Production and Exploration	2015			2014		% Change
	(Dollars in thousands)
Revenues-Oil	$	5,864		$	10,331		(43.2	)%
Revenues - Natural gas and liquids		636			1,673		(62.0	)%
Revenues-Total		6,500			12,004		(45.9	)%
Direct operating costs		2,798			3,274		(14.5	)%
Margin (1)		3,702			8,730		(57.6	)%
Depletion and impairment		8,264			6,027		37.1	%
Operating income	$	(4,562	)	$	2,703		(268.8	)%
Capital expenditures	$	7,592		$	8,684		(12.6	)%

Revenues decreased as a result of lower commodity prices and a decline in oil production. Direct operating costs include a reduction in taxes due to lower revenues and lower exploration costs. Depletion and impairment expense in 2015 includes approximately $3.4 million of oil and natural gas property impairments compared to approximately $1.0 million of oil and natural gas property impairments in 2014.

Corporate and Other	2015			2014			% Change
	(Dollars in thousands)
Selling, general and administrative	$	14,006		$	13,157			6.5	%
Depreciation	$	1,367		$	1,134			20.5	%
Net (gain) loss on asset disposals	$	(2,916	)	$	(1,744	)		67.2	%
Interest income	$	283		$	176			60.8	%
Interest expense	$	8,541		$	7,188			18.8	%
Capital expenditures	$	643		$	468			37.4	%

Gains and losses on the disposal of assets are treated as part of our corporate activities because such transactions relate to corporate strategy decisions of our executive management group. Interest expense increased primarily due to borrowing on the revolving credit facility. There were no borrowings under the revolving credit facility during the first quarter of 2014.

Adjusted earnings before interest, taxes, depreciation and amortization (“Adjusted EBITDA”) is not defined by accounting principles generally accepted in the United States of America (“U.S. GAAP”). We define Adjusted EBITDA as net income plus net interest expense, income tax expense and depreciation, depletion, amortization and impairment expense. We present Adjusted EBITDA (a non-U.S. GAAP measure) because we believe it provides to both management and investors additional information with respect to both the performance of our fundamental business activities and our ability to meet our capital expenditures and working capital requirements. Adjusted EBITDA should not be construed as an alternative to the U.S. GAAP measures of net income or operating cash flow.

Our effective income tax rate was 42.4% for the three months ended March 31, 2015, compared to 32.7% for the three months ended March 31, 2014. The Domestic Production Activities Deduction was enacted as part of the American Jobs Creation Act of 2004 (as revised by the Emergency Economic Stabilization Act of 2008), and allows a deduction of 9% on the lesser of qualified production activities income or taxable income. For financial statement purposes, we expect a loss before income taxes for the year ending December 31, 2015; however, we currently expect to have taxable income for the year ending December 31, 2015, and the Domestic Production Activities Deduction is expected to provide a permanent tax benefit. The interplay between the expected loss before income taxes for financial statement purposes and the permanent tax benefit expected to be provided by the Domestic Production Activities Deduction results in a higher effective income tax rate for the three months ended March 31, 2015.

In May 2014, the FASB issued an accounting standards update to provide guidance on the recognition of revenue from customers. Under this guidance, an entity will recognize revenue when it transfers promised goods or services to customers in an amount that reflects what it expects in exchange for the goods or services. This guidance also requires more detailed disclosures to enable users of the financial statements to understand the nature, amount, timing and uncertainty, if any, of revenue and cash flows arising from contracts with customers. The requirements in this update are effective during interim and annual periods beginning after December 15, 2017. We are currently evaluating the impact this guidance will have on our consolidated financial statements.

Volatility of Oil and Natural Gas Prices and its Impact on Operations and Financial Condition

Our revenue, profitability and cash flows are highly dependent upon prevailing prices for oil and natural gas and expectations about future prices. For many years, oil and natural gas prices and markets have been extremely volatile. Prices are affected by many factors beyond our control. During the nine months ended September 30, 2014, oil prices averaged $99.96 per barrel, natural gas prices averaged $4.59 per Mcf and demand for drilling activities increased. During the three months ended December 31, 2014, drilling activity slowed as oil prices averaged $73.16 per barrel and natural gas prices averaged $3.80 per Mcf. During the three months ended March 31, 2015, oil prices averaged $48.59 per barrel and natural gas prices averaged $2.90 per Mcf. Drilling activity has significantly decreased since December 31, 2014. Our average number of rigs operating remains well below the number of our available rigs, and given current oil and natural gas pricing and existing market trends, we expect our average number of rigs operating to continue to decline through at least the second quarter of 2015.

We expect oil and natural gas prices to continue to be volatile and to affect our financial condition, operations and ability to access sources of capital. Continued low market prices for oil and natural gas will likely result in decreased demand for our drilling rigs and pressure pumping services and adversely affect our operating results, financial condition and cash flows. Even during periods of high prices for oil and natural gas, companies exploring for oil and natural gas may cancel or curtail programs, or reduce their levels of capital expenditures for exploration and production for a variety of reasons, which could reduce demand for our drilling rigs and pressure pumping services.

We currently have exposure to interest rate market risk associated with any borrowings that we have under the Credit Agreement and the 2015 Term Loan Agreement.

Under the Credit Agreement, interest is paid on the outstanding principal amount of borrowings at a floating rate based on, at our election, LIBOR or a base rate. The margin on LIBOR loans ranges from 2.25% to 3.25% and the margin on base rate loans ranges from 1.25% to 2.25%, based on our debt to capitalization ratio. At March 31, 2015, the margin on LIBOR loans was 2.25% and the margin on base rate loans was 1.25%. Based on our debt to capitalization ratio at December 31, 2014, the applicable margin on LIBOR loans is 2.75% and the applicable margin on base rate loans is 1.75% as of April 1, 2015. Based on our debt to capitalization ratio at March 31, 2015, the applicable margin on LIBOR loans will be 2.25% and the applicable margin on base rate loans will be 1.25% as of July 1, 2015. As of March 31, 2015, we had no amounts outstanding under our revolving credit facility and $80.0 million outstanding under our term loan facility at an interest rate of 2.625%. The interest rate on the borrowings outstanding under our revolving credit and term loan facilities is variable and adjusts at each interest payment date based on our election of LIBOR or the base rate.

Loans under the 2015 Term Loan Agreement bear interest, at out election, at the per annum rate of LIBOR plus 3.25% or base rate plus 2.25%. As of March 31, 2015, we had $200 million outstanding under the 2015 Term Loan Agreement at an interest rate of 3.625%.

Under the Reimbursement Agreement, we will reimburse Scotiabank on demand for any amounts that Scotiabank has disbursed under any letters of credit. We are obligated to pay to Scotiabank interest on all amounts not paid by us on the date of demand or when otherwise due at the LIBOR rate plus 2.25% per annum. As of March 31, 2015, no amounts had been disbursed under any letters of credit.

We conduct a portion of our business in Canadian dollars through our Canadian land-based drilling operations. The exchange rate between Canadian dollars and U.S. dollars has fluctuated during the last several years. If the value of the Canadian dollar against the U.S. dollar weakens, revenues and earnings of our Canadian operations will be reduced and the value of our Canadian net assets will decline when they are translated to U.S. dollars. This currency risk is not material to our results of operations or financial condition.

The carrying values of cash and cash equivalents, trade receivables and accounts payable approximate fair value due to the short-term maturity of these items.

Disclosure Controls and Procedures — We maintain disclosure controls and procedures (as such terms are defined in Rules 13a-15(e) and 15d-15(e) promulgated under the Exchange Act), designed to ensure that the information required to be disclosed in the reports that we file with the SEC under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”), as appropriate, to allow timely decisions regarding required disclosure.

Under the supervision and with the participation of our management, including our CEO and CFO, we conducted an evaluation of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this Quarterly Report on Form 10‑Q. Based on that evaluation, our CEO and CFO concluded that our disclosure controls and procedures were effective as of March 31, 2015.

Changes in Internal Control Over Financial Reporting —There were no changes in our internal control over financial reporting during our most recently completed fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting, as defined in Rule 13a-15(f) under the Exchange Act.

In May 2013, the U.S. Equal Employment Opportunity Commission (“EEOC”) notified us of cause findings related to certain employment practices of our U.S. drilling subsidiary. In March 2015, the EEOC filed a lawsuit, and on the same day the EEOC and our subsidiary filed a consent decree agreeing to settle the lawsuit on a no-fault basis and requiring the subsidiary to pay $12.26 million into a settlement fund for eligible participants. On April 17, 2015, a Federal court judge approved and signed the consent decree, which resolved the allegations in the lawsuit that our subsidiary engaged in a pattern or practice of nationwide discrimination based on race, color, and/or national origin in three respects: (i) creating and/or tolerating a hostile work environment, (ii) disparate treatment in terms and conditions of employment and (iii) retaliation.

Other than the matters described above, we are party to various other legal proceedings arising in the normal course of our business; we do not believe that the outcome of these proceedings, either individually or in the aggregate, will have a material adverse effect on our financial condition, results of operations or cash flows.

The table below sets forth the information with respect to purchases of our common stock made by us during the quarter ended March 31, 2015.

							Approximate Dollar
					Total Number of		Value of Shares
					Shares (or Units)		That May Yet Be
					Purchased as Part		Purchased Under the
	Total		Average Price		of Publicly		Plans or
	Number of Shares		Paid per		Announced Plans		Programs (in
Period Covered	Purchased		Share		or Programs		thousands)(1)
January 2015		—		—	—			187,016
February 2015	—		—		—			187,016
March 2015		—		—		—		187,016
Total		—		—		—		187,016

The following exhibits are filed herewith or incorporated by reference, as indicated:

3.1		Restated Certificate of Incorporation, as amended (filed August 9, 2004 as Exhibit 3.1 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2004 and incorporated herein by reference).

3.2		Amendment to Restated Certificate of Incorporation, as amended (filed August 9, 2004 as Exhibit 3.2 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2004 and incorporated herein by reference).

3.3		Second Amended and Restated Bylaws (filed August 6, 2007 as Exhibit 3.3 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2007 and incorporated herein by reference).

10.1		Amendment No. 1 to Credit Agreement, dated as of January 9, 2015, by and among the Company, certain subsidiaries of the Company party thereto, Wells Fargo Bank, N.A., as administrative agent, issuer of letters of credit and swing line lender and the other lenders thereto (filed January 12, 2015 as Exhibit 10.1 to the Company’s Current Report on Form 8-K and incorporated herein by reference).

10.2		Reimbursement Agreement, dated as of March 16, 2015, by and between the Company and The Bank of Nova Scotia (filed March 16, 2015 as Exhibit 10.1 to the Company’s Current Report on Form 8-K and incorporated herein by reference).

10.3		Continuing Guaranty, dated as of March 16, 2015, by Patterson Petroleum, LLC, Patterson-UTI Drilling Company LLC, Patterson-UTI Management Services, LLC, Universal Well Services, Inc. and Universal Pressure Pumping, Inc. (filed March 16, 2015 as Exhibit 10.2 to the Company’s Current Report on Form 8-K and incorporated herein by reference).

10.4		Term Loan Agreement, dated as of March 18, 2015, among Patterson-UTI Energy, Inc., as borrower, Wells Fargo Bank, N.A., as administrative agent and lender, each of the other lenders party thereto, Wells Fargo Securities, LLC, as Lead Arranger and Sole Book Runner, and Bank of America, N.A. and The Bank Of Tokyo-Mitsubishi UFJ, LTD., as Co-Syndication Agents (filed March 18, 2015 as Exhibit 10.1 to the Company’s Current Report on Form 8-K and incorporated herein by reference).

10.5		Continuing Guaranty, dated as of March 18, 2015, by Patterson Petroleum LLC, Patterson-UTI Drilling Company LLC, Patterson-UTI Management Services, LLC, Universal Well Services, Inc. and Universal Pressure Pumping, Inc. (filed March 18, 2015 as Exhibit 10.2 to the Company’s Current Report on Form 8-K and incorporated herein by reference).

31.1*		Certification of Chief Executive Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended.

31.2*		Certification of Chief Financial Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended.

32.1*		Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 USC Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101*		The following materials from Patterson-UTI Energy, Inc.’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2015, formatted in XBRL (Extensible Business Reporting Language): (i) the Consolidated Condensed Balance Sheets, (ii) the Consolidated Condensed Statements of Operations, (iii) the Consolidated Condensed Statements of Comprehensive Income, (iv) the Consolidated Condensed Statement of Changes in Stockholders’ Equity, (v) the Consolidated Condensed Statements of Cash Flows, and (vi) Notes to Consolidated Condensed Financial Statements.

Pursuant to the requirements 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.

DELAWARE		75-2504748
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

450 GEARS ROAD, SUITE 500 HOUSTON, TEXAS		77067
(Address of principal executive offices)		(Zip Code)

Large accelerated filer	R	Accelerated filer	¨

Non-accelerated filer	¨	Smaller reporting company	¨

	PART I — FINANCIAL INFORMATION
		Page
ITEM 1.	Financial Statements
	Unaudited consolidated condensed balance sheets	3
	Unaudited consolidated condensed statements of operations	4
	Unaudited consolidated condensed statements of comprehensive income	5
	Unaudited consolidated condensed statement of changes in stockholders’ equity	6
	Unaudited consolidated condensed statements of cash flows	7
	Notes to unaudited consolidated condensed financial statements	8
ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	21
ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	31
ITEM 4.	Controls and Procedures	31

	PART II — OTHER INFORMATION

ITEM 1.	Legal Proceedings	32
ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	32
ITEM 6.	Exhibits	33
Signature		34

				Weighted
				Average
				Grant Date
	Shares			Fair Value
Non-vested restricted stock outstanding at January 1, 2015		1,493,059		$	26.93
Granted		18,000		$	16.59
Vested		(57,356	)	$	21.65
Forfeited		(15,590	)	$	28.08
Non-vested restricted stock outstanding March 31, 2015		1,438,113		$	27.00

	March 31,			December 31,
	2015			2014
Equipment	$	6,891,544		$	6,679,894
Oil and natural gas properties		200,390			196,234
Buildings		88,393			83,465
Land		12,024			12,038
		7,192,351			6,971,631
Less accumulated depreciation, depletion and impairment		(2,969,947	)		(2,840,560	)
Property and equipment, net	$	4,222,404		$	4,131,071

	2014		2013		2012		2011
	Performance		Performance		Performance		Performance
	Unit Awards		Unit Awards		Unit Awards		Unit Awards
Target number of shares		154,000		236,500		192,000		144,375

	Contract		Pressure
	Drilling		Pumping		Total
Balance December 31, 2014	$	86,234	$	124,561	$	210,795
Changes to goodwill	—		—			—
Balance March 31, 2015	$	86,234	$	124,561	$	210,795

Year ending December 31,
2015	$	25,000
2016		63,750
2017		191,250
2018		—
2019		—
Thereafter		600,000
Total	$	880,000

2014:	Per Share		Total
			(in thousands)
Paid on March 27, 2014	$	0.10	$	14,456

2015:	Per Share		Total
			(in thousands)
Paid on March 25, 2015	$	0.10	$	14,640

	Three Months Ended March 31,
	2015				2014
Contract drilling	$	401,478	61	%	$	425,903	63	%
Pressure pumping		249,721	38	%		240,261	35	%
Oil and natural gas		6,500	1	%		12,004	2	%
	$	657,699	100	%	$	678,168	100	%

PATTERSON-UTI ENERGY, INC.

By:		/s/ John E. Vollmer III
		John E. Vollmer III
		Senior Vice President – Corporate Development,
		Chief Financial Officer and Treasurer
		(Principal Financial and Accounting Officer and Duly Authorized Officer)