ois20170630_10q.htm

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.

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 (§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).

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

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) 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).

As of July 27, 2017, the number of shares of common stock outstanding was 51,100,302.

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2017			2016			2017			2016
Revenues:
Products	$	82,750		$	111,656		$	155,930		$	214,254
Service		88,652			64,193			166,939			131,250
		171,402			175,849			322,869			345,504

Costs and expenses:
Product costs		59,309			83,939			109,659			152,512
Service costs		72,539			52,461			141,101			112,703
Selling, general and administrative expense		29,482			30,486			57,212			60,466
Depreciation and amortization expense		27,784			29,415			55,764			59,817
Other operating (income) expense, net		794			(3,291	)		963			(2,728	)
		189,908			193,010			364,699			382,770
Operating loss		(18,506	)		(17,161	)		(41,830	)		(37,266	)

Interest expense		(1,149	)		(1,315	)		(2,223	)		(2,760	)
Interest income		85			110			170			202
Other income		273			224			270			430
Loss from continuing operations before income taxes		(19,297	)		(18,142	)		(43,613	)		(39,394	)
Income tax benefit		5,051			6,437			11,689			14,453
Net loss from continuing operations		(14,246	)		(11,705	)		(31,924	)		(24,941	)
Net loss from discontinued operations, net of tax		–			(1	)		–			(4	)
Net loss attributable to Oil States	$	(14,246	)	$	(11,706	)	$	(31,924	)	$	(24,945	)


Basic net loss per share attributable to Oil States from:
Continuing operations	$	(0.28	)	$	(0.23	)	$	(0.63	)	$	(0.50	)
Discontinued operations		–			–			–			–
Net loss	$	(0.28	)	$	(0.23	)	$	(0.63	)	$	(0.50	)

Diluted net loss per share attributable to Oil States from:
Continuing operations	$	(0.28	)	$	(0.23	)	$	(0.63	)	$	(0.50	)
Discontinued operations		–			–			–			–
Net loss	$	(0.28	)	$	(0.23	)	$	(0.63	)	$	(0.50	)

Weighted average number of common shares outstanding:
Basic		50,232			50,210			50,296			50,126
Diluted		50,232			50,210			50,296			50,126

	June 30,			December 31,
	2017			2016
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	72,468		$	68,800
Accounts receivable, net		213,075			234,513
Inventories, net		169,622			175,490
Prepaid expenses and other current assets		11,112			11,174
Total current assets		466,277			489,977

Property, plant, and equipment, net		522,815			553,402
Goodwill, net		268,698			263,369
Other intangible assets, net		52,111			52,746
Other noncurrent assets		37,927			24,404
Total assets	$	1,347,828		$	1,383,898

LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities:
Current portion of long-term debt and capitalized leases	$	522		$	538
Accounts payable		34,957			34,207
Accrued liabilities		41,817			45,018
Income taxes payable		2,658			5,839
Deferred revenue		20,506			21,315
Other current liabilities		318			315
Total current liabilities		100,778			107,232

Long-term debt and capitalized leases		50,367			45,388
Deferred income taxes		3,500			5,036
Other noncurrent liabilities		22,696			21,935
Total liabilities		177,341			179,591

Stockholders’ equity:
Common stock, $.01 par value, 200,000,000 shares authorized, 62,722,686 shares and 62,295,870 shares issued, respectively		627			623
Additional paid-in capital		742,512			731,562
Retained earnings		1,101,549			1,133,473
Accumulated other comprehensive loss		(61,667	)		(70,300	)
Treasury stock, at cost, 11,626,979 and 10,921,509 shares, respectively		(612,534	)		(591,051	)
Total stockholders’ equity		1,170,487			1,204,307
Total liabilities and stockholders’ equity	$	1,347,828		$	1,383,898

	Six Months Ended June 30,
	2017			2016

Cash flows from operating activities:
Net loss	$	(31,924	)	$	(24,945	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Loss from discontinued operations		–			4
Depreciation and amortization		55,764			59,817
Stock-based compensation expense		10,954			10,569
Deferred income tax benefit		(14,917	)		(20,206	)
Provision for bad debt		210			784
Gain on disposals of assets		(210	)		(372	)
Amortization of deferred financing costs		405			390
Other, net		29			665
Changes in operating assets and liabilities, net of effect from acquired businesses:
Accounts receivable		23,404			62,321
Inventories		8,689			7,677
Accounts payable and accrued liabilities		(3,075	)		(14,798	)
Income taxes payable		(3,211	)		5,908
Other operating assets and liabilities, net		(1,191	)		(5,688	)
Net cash flows provided by continuing operating activities		44,927			82,126
Net cash flows used in discontinued operating activities		–			(6	)
Net cash flows provided by operating activities		44,927			82,120

Cash flows from investing activities:
Capital expenditures		(13,291	)		(18,398	)
Acquisitions of businesses		(12,859	)		–
Proceeds from disposition of property, plant and equipment		742			546
Other, net		(453	)		(1,551	)
Net cash flows used in investing activities		(25,861	)		(19,403	)

Cash flows from financing activities:
Revolving credit facility borrowings (repayments), net		4,825			(42,422	)
Debt and capital lease repayments		(267	)		(263	)
Purchase of treasury stock		(16,283	)		–
Issuance of common stock from stock-based payment arrangements		–			366
Shares added to treasury stock as a result of net share settlements due to vesting of restricted stock		(5,200	)		(3,924	)
Net cash flows used in financing activities		(16,925	)		(46,243	)

Effect of exchange rate changes on cash and cash equivalents		1,527			(490	)
Net change in cash and cash equivalents		3,668			15,984
Cash and cash equivalents, beginning of period		68,800			35,973

Cash and cash equivalents, end of period	$	72,468		$	51,957

1.	Organization and Basis of Presentation

The accompanying unaudited condensed consolidated financial statements of Oil States International, Inc. and its subsidiaries (referred to in this report as “we” or the “Company”) have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (the “Commission”) pertaining to interim financial information. Certain information in footnote disclosures normally included in financial statements prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) have been condensed or omitted pursuant to these rules and regulations. The unaudited financial statements included in this report reflect all the adjustments, consisting of normal recurring adjustments, which the Company considers necessary for a fair presentation of the results of operations for the interim periods covered and for the financial condition of the Company at the date of the interim balance sheet. Results for the interim periods are not necessarily indicative of results for the full year.

The preparation of condensed consolidated financial statements in conformity with GAAP requires the use of estimates and assumptions by management in determining the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the condensed consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. If the underlying estimates and assumptions, upon which the financial statements are based, change in future periods, actual amounts may differ from those included in the accompanying condensed consolidated financial statements. Our industry is cyclical and this cyclicality impacts our estimates of the period over which future cash flows will be generated, as well as the predictability of these cash flows including our determination of whether a decline in value of our deferred tax assets, long-lived assets and/or goodwill has occurred.

During the first quarter of 2017, we modified the name of our “Offshore Products” segment to the “Offshore/Manufactured Products” segment given the higher proportional weighting of our shorter-cycle manufactured products (much of which is driven by land-based activity) to the total revenues generated by the segment. The Company has also provided supplemental disclosure in Note 12, “Segments and Related Information,” with respect to product and service revenues generated by the Offshore/Manufactured Products segment, including project-driven products, short-cycle products, and other products and services. There have been no operational, reporting or other material changes related to the Offshore/Manufactured Products segment.

The financial statements included in this report should be read in conjunction with the Company’s audited financial statements and accompanying notes included in its Annual Report on Form 10-K for the year ended December 31, 2016 (the “2016 Form 10-K”).

2.	Recent Accounting Pronouncements

From time to time, new accounting pronouncements are issued by the Financial Accounting Standards Board (the “FASB”), which are adopted by the Company as of the specified effective date. Unless otherwise discussed, management believes that the impact of recently issued standards, which are not yet effective, will not have a material impact on the Company’s consolidated financial statements upon adoption.

In May 2014, the FASB issued guidance on revenue from contracts with customers that will supersede most current revenue recognition guidance, including industry-specific guidance. The underlying principle is that an entity will recognize revenue to depict the transfer of goods or services to customers at an amount that the entity expects to be entitled to receive in exchange for those goods or services. The guidance permits the use of either a retrospective or modified retrospective transition method. The Company will adopt this guidance on January 1, 2018, using the modified retrospective transition method applied to those contracts which are not completed as of that date. Upon adoption, we will recognize any cumulative effect of adopting this guidance as an adjustment to our opening balance of retained earnings. Prior periods will not be retrospectively adjusted. We continue to review our contracts with certain customers (primarily those related to project-driven products) within our Offshore/Manufactured Products segment to determine the potential impact of the standard on such contracts and on our consolidated financial statements. In accordance with the guidance, we expect to expand our revenue recognition disclosures in 2018 to address the new qualitative and quantitative requirements.

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED

FINANCIAL STATEMENTS

(Continued)

In February 2016, the FASB issued guidance on leases which introduces the recognition of lease assets and lease liabilities by lessees for all leases which are not short-term in nature. The new standard requires a modified retrospective transition for capital or operating leases existing at or entered into after the beginning of the earliest comparative period presented in the financial statements. The Company will adopt this guidance on January 1, 2019. Upon initial evaluation, we believe the key change upon adoption will be the balance sheet recognition of our operating leases when we are the lessee. The income statement recognition appears similar to our current methodology. The Company’s future obligations under operating leases as of December 31, 2016 are summarized in Note 14, “Commitments and Contingencies,” in our 2016 Form 10-K.

In March 2016, the FASB issued guidance on employee share-based payment accounting which modifies existing guidance related to the accounting for forfeitures, employer tax withholding on stock-based compensation and the financial statement presentation of excess tax benefits or deficiencies. The Company adopted this guidance on January 1, 2017. Adoption of this standard had no retrospective impact on the Company’s financial statements and the impact on the Company’s income tax benefit during the first six months of 2017 was not material.

In January 2017, the FASB issued guidance which simplifies the test of goodwill impairment. Under the revised standard, the Company will no longer be required to determine the implied fair value of goodwill by assigning the fair value of a reporting unit to its individual assets and liabilities as if that reporting unit had been acquired in a business combination. The revised guidance requires a prospective transition and permits early adoption for interim and annual goodwill impairment tests performed after January 1, 2017. The Company adopted this standard effective January 1, 2017.

In January 2017, the FASB issued guidance clarifying the definition of a business to assist entities with evaluating when a group of transferred assets and activities is a business in connection with a business combination. The revised standard provides that if substantially all of the fair value of the gross assets acquired is concentrated in a single identifiable asset or a set of similar identifiable assets, the group of transferred assets and activities is not a business. The Company adopted this standard effective January 1, 2017.

3.	Details of Selected Balance Sheet Accounts

Additional information regarding selected balance sheet accounts at June 30, 2017 and December 31, 2016 is presented below (in thousands):

	June 30,			December 31,
	2017			2016
Accounts receivable, net:
Trade	$	160,482		$	173,087
Unbilled revenue		56,007			64,564
Other		4,803			5,372
Total accounts receivable		221,292			243,023
Allowance for doubtful accounts		(8,217	)		(8,510	)
	$	213,075		$	234,513

	June 30,			December 31,
	2017			2016
Inventories, net:
Finished goods and purchased products	$	84,191		$	87,241
Work in process		31,618			30,584
Raw materials		69,357			72,514
Total inventories		185,166			190,339
Allowance for excess or obsolete inventory		(15,544	)		(14,849	)
	$	169,622		$	175,490

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED

FINANCIAL STATEMENTS

(Continued)

	Estimated				June 30,			December 31,
	Useful Life (years)				2017			2016
Property, plant and equipment, net:
Land					$	31,888		$	31,683
Buildings and leasehold improvements		3	-	40		230,463			227,642
Machinery and equipment		2	-	28		463,786			455,873
Completion services equipment		2	-	10		425,606			429,845
Office furniture and equipment		3	-	10		44,115			42,827
Vehicles		2	-	10		120,297			121,317
Construction in progress						34,137			27,519
Total property, plant and equipment						1,350,292			1,336,706
Accumulated depreciation						(827,477	)		(783,304	)
					$	522,815		$	553,402

	June 30,		December 31,
	2017		2016
Other noncurrent assets:
Deferred compensation plan	$	19,588	$	18,772
Deferred income taxes		12,952		120
Other		5,387		5,512
	$	37,927	$	24,404

	June 30,		December 31,
	2017		2016
Accrued liabilities:
Accrued compensation	$	18,152	$	23,131
Insurance liabilities		7,602		8,099
Accrued taxes, other than income taxes		5,983		2,461
Accrued leasehold restoration liability		807		766
Accrued product warranty reserves		764		1,113
Accrued commissions		1,568		1,305
Accrued claims		1,416		1,578
Other		5,525		6,565
	$	41,817	$	45,018

5.	Net Loss Per Share

The table below provides a reconciliation of the numerators and denominators of basic and diluted net loss per share for the three and six months ended June 30, 2017 and 2016 (in thousands, except per share amounts):

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2017			2016			2017			2016
Numerators:
Net loss from continuing operations	$	(14,246	)	$	(11,705	)	$	(31,924	)	$	(24,941	)
Less: Income attributable to unvested restricted stock awards		–			–			–			–
Numerator for basic net loss per share from continuing operations		(14,246	)		(11,705	)		(31,924	)		(24,941	)
Net loss from discontinued operations, net of tax		–			(1	)		–			(4	)
Numerator for basic net loss per share attributable to Oil States		(14,246	)		(11,706	)		(31,924	)		(24,945	)
Effect of dilutive securities:
Unvested restricted stock awards		–			–			–			–
Numerator for diluted net loss per share attributable to Oil States	$	(14,246	)	$	(11,706	)	$	(31,924	)	$	(24,945	)

Denominators:
Weighted average number of common shares outstanding		51,350			51,348			51,421			51,254
Less: Weighted average number of unvested restricted stock awards outstanding		(1,118	)		(1,138	)		(1,125	)		(1,128	)
Denominator for basic net loss per share attributable to Oil States		50,232			50,210			50,296			50,126
Effect of dilutive securities:
Unvested restricted stock awards		–			–			–			–
Assumed exercise of stock options		–			–			–			–
		–			–			–			–
Denominator for diluted net loss per share attributable to Oil States		50,232			50,210			50,296			50,126

Basic net loss per share attributable to Oil States from:
Continuing operations	$	(0.28	)	$	(0.23	)	$	(0.63	)	$	(0.50	)
Discontinued operations		–			–			–			–
Net loss	$	(0.28	)	$	(0.23	)	$	(0.63	)	$	(0.50	)

Diluted net loss per share attributable to Oil States from:
Continuing operations	$	(0.28	)	$	(0.23	)	$	(0.63	)	$	(0.50	)
Discontinued operations		–			–			–			–
Net loss	$	(0.28	)	$	(0.23	)	$	(0.63	)	$	(0.50	)

The calculation of diluted net loss per share for the three and six months ended June 30, 2017 excluded 715 thousand shares and 718 thousand shares, respectively, issuable pursuant to outstanding stock options and restricted stock awards, due to their antidilutive effect. The calculation of diluted net loss per share for the three and six months ended June 30, 2016 excluded 757 thousand shares and 759 thousand shares, respectively, issuable pursuant to outstanding stock options and restricted stock awards, due to their antidilutive effect.

6.	Business Acquisitions and Goodwill

In January 2017, our Offshore/Manufactured Products segment acquired the intellectual property and assets of complementary product lines to our global crane manufacturing and service operations. The acquisition included adding active heave compensation technology and knuckle-boom crane designs to our existing portfolio.

In April 2017, our Offshore/Manufactured Products segment acquired assets and intellectual property that are complementary to our riser testing, inspection and repair service offerings. This complimentary technology allows the segment to provide automated inspection techniques either on board an offshore vessel or on the quayside, without the requirements to transport to a facility to remove the buoyancy materials.

Using cash on hand, consideration paid in connection with these transactions totaled $12.9 million, which was allocated to the net assets acquired, including intangibles and goodwill. While no material adjustments are anticipated, the Company’s allocations of purchase price are preliminary and subject to change primarily based on the final determination of the fair values of intangible assets acquired.

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED

FINANCIAL STATEMENTS

(Continued)

Changes in the carrying amount of goodwill for the six month period ended June 30, 2017 were as follows (in thousands):

	Well Site Services
	Completion Services			Drilling Services			Subtotal			Offshore / Manufactured Products		Total
Balance as of December 31, 2016
Goodwill	$	199,278		$	22,767		$	222,045		$	158,619	$	380,664
Accumulated impairment losses		(94,528	)		(22,767	)		(117,295	)		–		(117,295	)
		104,750			–			104,750			158,619		263,369
Goodwill acquired		–			–			–			4,698		4,698
Foreign currency translation		353			–			353			278		631
Balance as of June 30, 2017	$	105,103		$	–		$	105,103		$	163,595	$	268,698

Balance as of June 30, 2017
Goodwill	$	199,631		$	22,767		$	222,398		$	163,595	$	385,993
Accumulated impairment losses		(94,528	)		(22,767	)		(117,295	)		–		(117,295	)
	$	105,103		$	–		$	105,103		$	163,595	$	268,698

7.	Long-term Debt

As of June 30, 2017 and December 31, 2016, long-term debt consisted of the following (in thousands):

	June 30, 2017			December 31, 2016

Revolving credit facility⁽¹⁾	$	45,460		$	40,230
Capital lease obligations and other debt		5,429			5,696
Total debt		50,889			45,926
Less: Current portion		(522	)		(538	)
Total long-term debt and capitalized leases	$	50,367		$	45,388

(1)

Amounts presented are net of $1.6 million and $2.0 million, respectively, of unamortized debt issuance costs.

Revolving Credit Facility

The Company has a $600 million senior secured revolving credit facility (the “Revolving Credit Facility”) with an option to increase the maximum borrowings to $750 million subject to additional lender commitments prior to its maturity on May 28, 2019. As of June 30, 2017, we had $47.0 million outstanding under the Credit Agreement (as defined below) and an additional $24.0 million of outstanding letters of credit, leaving $128.0 million available to be drawn under the Revolving Credit Facility. The total amount available to be drawn was less than the lender commitments as of June 30, 2017, due to the maximum leverage ratio covenant in the Credit Agreement which serves to limit borrowings. We expect our availability to continue to be limited by the maximum leverage ratio covenant in 2017 based upon our forecast of our trailing twelve-month EBITDA (as defined in the Credit Agreement and further discussed below).

The Revolving Credit Facility is governed by a Credit Agreement dated as of May 28, 2014, as amended, (the “Credit Agreement”) by and among the Company, the Lenders party thereto, Wells Fargo Bank, N.A., as administrative agent, the Swing Line Lender and an Issuing Bank, and Royal Bank of Canada, as Syndication agent, and Compass Bank, as Documentation agent. Amounts outstanding under the Revolving Credit Facility bear interest at LIBOR plus a margin of 1.50% to 2.50%, or at a base rate plus a margin of 0.50% to 1.50%, in each case based on a ratio of the Company’s total leverage to EBITDA. During the first half of 2017, our applicable margin over LIBOR was 1.50%. We must also pay a quarterly commitment fee, based on our leverage ratio, on the unused commitments under the Credit Agreement. The unused commitment fee was 0.375% during the first half of 2017. The Credit Agreement contains customary financial covenants and restrictions. Specifically, we must maintain an interest coverage ratio, defined as the ratio of consolidated EBITDA to consolidated interest expense, of at least 3.0 to 1.0 and a maximum leverage ratio, defined as the ratio of total debt to consolidated EBITDA, of no greater than 3.25 to 1.0. Each of the factors considered in the calculations of these ratios are defined in the Credit Agreement. EBITDA and consolidated interest, as defined, exclude goodwill impairments, losses on extinguishment of debt, debt discount amortization, and other non-cash charges. As of June 30, 2017, we were in compliance with our debt covenants.

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED

FINANCIAL STATEMENTS

(Continued)

Borrowings under the Credit Agreement are secured by a pledge of substantially all of our assets and the assets of our domestic subsidiaries. Our obligations under the Credit Agreement are guaranteed by our significant domestic subsidiaries. The Revolving Credit Facility also contains negative covenants that limit the Company's ability to borrow additional funds, encumber assets, pay dividends, sell assets and enter into other significant transactions.

Under the Credit Agreement, the occurrence of specified change of control events involving our Company would constitute an event of default that would permit the banks to, among other things, accelerate the maturity of the facility and cause it to become immediately due and payable in full.

10.

Stock-based Compensation

The following table presents a summary of activity for stock options, service-based restricted stock awards and performance-based stock unit awards for the six months ended June 30, 2017.

	Stock Options			Service-based Restricted Stock			Performance-based Stock Units
Outstanding at December 31, 2016		715,095			1,140,489			157,925
Granted		–			468,544			74,758
Restricted stock awards vested		–			(453,625	)		–
Forfeited		(19,182	)		(41,728	)		–
Outstanding at June 30, 2017		695,913			1,113,680			232,683
Weighted average grant date fair value (2017 awards)	$	–		$	39.71		$	62.66

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED

FINANCIAL STATEMENTS

(Continued)

The restricted stock program consists of a combination of service-based restricted stock and performance-based stock units. The service-based restricted stock awards generally vest on a straight-line basis over their term, which is generally three to four years. The number of performance-based restricted shares ultimately issued under the program is dependent upon our achievement of a predefined specific performance measures generally measured over a three-year period. In the event the predefined targets are exceeded for any performance-based award, additional shares up to a maximum of 200% of the target award may be granted. Conversely, if actual performance falls below the predefined target, the number of shares vested is reduced. If the actual performance falls below the threshold performance level, no restricted shares will vest. The performance measure for the 2017 and 2016 awards is relative total stockholder return compared to our peer group of companies while the performance measure specified for the 2015 awards was average after-tax return on invested capital. Currently, it is unlikely that the 2015 performance measure threshold will be met which would result in a performance award forfeiture of approximately 80 thousand units in 2017.

Stock-based compensation pre-tax expense recognized in the three-month periods ended June 30, 2017 and 2016 totaled $6.0 million and $5.5 million, respectively. Stock-based compensation pre-tax expense recognized in the six-month periods ended June 30, 2017 and 2016 totaled $11.0 million and $10.6 million, respectively. As of June 30, 2017, there was $39.6 million of pre-tax compensation costs related to service-based and performance-based stock awards and unvested stock options, which will be recognized in future periods as vesting conditions are satisfied.

12.

Segments and Related Information

The Company operates through two reportable segments: Well Site Services and Offshore/Manufactured Products. The Company’s reportable segments represent strategic business units that offer different products and services. They are managed separately because each business requires different technologies and marketing strategies. Acquisitions have been direct extensions to our business segments. Separate business lines within the Well Site Services segment have been disclosed to provide additional information for that segment.

Our Well Site Services segment provides a broad range of equipment and services that are used to drill for, establish and maintain the flow of oil and natural gas from a well throughout its life cycle. In this segment, our operations primarily include completion-focused equipment and services as well as land drilling services. Our Completion Services operations provide solutions to our customers using our fleet of completion tools and highly-trained personnel throughout our service offerings which include: wireline support, frac stacks, isolations tools, extended reach tools, ball launchers, well testing operations, thru tubing activity and sand control. Drilling Services provides land drilling services for shallow to medium depth wells in West Texas and the Rocky Mountain region of the United States.

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED

FINANCIAL STATEMENTS

(Continued)

Our Offshore/Manufactured Products segment designs, manufactures and markets capital equipment utilized on floating production systems, subsea pipeline infrastructure, and offshore drilling rigs and vessels, along with short-cycle and other products. Driven principally by longer-term customer investments for offshore oil and natural gas projects, “project-driven product” revenues include: flexible bearings, advanced connector systems, high-pressure riser systems, deepwater mooring systems, cranes, subsea pipeline products and blow-out preventer stack integration. “Short-cycle products” manufactured by the segment include: valves, elastomers and other specialty products generally used in the land-based drilling and completion markets. “Other products,” manufactured and offered by the segment, include a variety of products for use in industrial, military and other applications outside the oil and gas industry. The segment also offers a broad line of complementary, value-added services including: specialty welding, fabrication, cladding and machining services, offshore installation services, and inspection and repair services.

Financial information by business segment for the three and six months ended June 30, 2017 and 2016 is summarized as follows (in thousands).

	Revenues		Depreciation and amortization		Operating (loss) income			Equity in losses of unconsolidated affiliates			Capital expenditures		Total assets
Three months ended June 30, 2017
Well Site Services –
Completion Services	$	57,890	$	16,193	$	(12,547	)	$	–		$	3,621	$	446,807
Drilling Services		11,477		4,794		(3,787	)		–			815		73,906
Total Well Site Services		69,367		20,987		(16,334	)		–			4,436		520,713
Offshore/Manufactured Products		102,035		6,534		10,662			(31	)		2,907		784,891
Corporate		–		263		(12,834	)		–			131		42,224
Total	$	171,402	$	27,784	$	(18,506	)	$	(31	)	$	7,474	$	1,347,828

	Revenues		Depreciation and amortization		Operating (loss) income			Equity in losses of unconsolidated affiliates			Capital expenditures		Total assets
Three months ended June 30, 2016
Well Site Services –
Completion Services	$	36,824	$	17,615	$	(21,466	)	$	-		$	2,129	$	489,750
Drilling Services		3,869		5,902		(5,951	)		-			246		87,001
Total Well Site Services		40,693		23,517		(27,417	)		-			2,375		576,751
Offshore/Manufactured Products		135,156		5,611		21,676			(97	)		5,583		877,609
Corporate		-		287		(11,420	)		-			160		28,476
Total	$	175,849	$	29,415	$	(17,161	)	$	(97	)	$	8,118	$	1,482,836

The Company has one customer whose revenue individually represented 16% and 15% of the Company’s consolidated product and service revenue for the three and six months ended June 30, 2017, respectively, and whose receivables individually represented 11% of the Company’s consolidated total accounts receivable as of June 30, 2017.

	Revenues		Depreciation and amortization		Operating (loss) income			Equity in losses of unconsolidated affiliates			Capital expenditures		Total assets
Six months ended June 30, 2017
Well Site Services –
Completion Services	$	106,562	$	32,721	$	(29,027	)	$	–		$	6,113	$	446,807
Drilling Services		22,958		9,829		(8,004	)		–			1,107		73,906
Total Well Site Services		129,520		42,550		(37,031	)		–			7,220		520,713
Offshore/Manufactured Products		193,349		12,687		20,126			(29	)		5,929		784,891
Corporate		–		527		(24,925	)		–			142		42,224
Total	$	322,869	$	55,764	$	(41,830	)	$	(29	)	$	13,291	$	1,347,828

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED

FINANCIAL STATEMENTS

(Continued)

	Revenues		Depreciation and amortization		Operating (loss) income			Equity in losses of unconsolidated affiliates			Capital expenditures		Total assets
Six months ended June 30, 2016
Well Site Services –
Completion Services	$	77,773	$	35,558	$	(45,801	)	$	-		$	6,667	$	489,750
Drilling Services		6,641		12,424		(14,056	)		-			499		87,001
Total Well Site Services		84,414		47,982		(59,857	)		-			7,166		576,751
Offshore/Manufactured Products		261,090		11,265		44,987			(119	)		10,974		877,609
Corporate		-		570		(22,396	)		-			258		28,476
Total	$	345,504	$	59,817	$	(37,266	)	$	(119	)	$	18,398	$	1,482,836

The following table provides supplemental revenue information for the Offshore/Manufactured Products segment for the three and six months ended June 30, 2017 and 2016 (in thousands):

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2017		2016		2017		2016

Project-driven products	$	34,582	$	83,767	$	66,917	$	157,899
Short-cycle products		40,020		18,579		73,091		39,267
Other products and services		27,433		32,810		53,341		63,924
	$	102,035	$	135,156	$	193,349	$	261,090

This Quarterly Report on Form 10-Q and other statements we make contain certain “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 (the “Securities Act”) and Section 21E of the Securities Exchange Act of 1934 (the “Exchange Act”). Actual results could differ materially from those projected in the forward-looking statements as a result of a number of important factors. For a discussion of known material factors that could affect our results, please refer to “Part I, Item 1. Business,” “Part I, Item 1A. Risk Factors,” “Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations” and “Part II, Item 7A. Quantitative and Qualitative Disclosures about Market Risk” included in our 2016 Form 10-K filed with the Securities and Exchange Commission on February 17, 2017 as well as “Part II, Item 1A, Rick Factors” included in this Quarterly Report on Form 10-Q.

You can typically identify "forward-looking statements" by the use of forward-looking words such as "may," "will," "could," "project," "believe," "anticipate," "expect," "estimate," "potential," "plan," "forecast," “proposed,” “should,” “seek,” and other similar words. Such statements may relate to our future financial position, budgets, capital expenditures, projected costs, plans and objectives of management for future operations and possible future strategic transactions. Where any such forward-looking statement includes a statement of the assumptions or bases underlying such forward-looking statement, we caution that assumed facts or bases almost always vary from actual results. The differences between assumed facts or bases and actual results can be material, depending upon the circumstances.

In any forward-looking statement where we express an expectation or belief as to future results, such expectation or belief is expressed in good faith and believed to have a reasonable basis. However, there can be no assurance that the statement of expectation or belief will result or be achieved or accomplished. The following are important factors that could cause actual results to differ materially from those expressed in any forward-looking statement made by, or on behalf of, our Company:

Should one or more of these risks or uncertainties materialize, or should the assumptions on which our forward-looking statements are based prove incorrect, actual results may differ materially from those expected, estimated or projected. In addition, the factors identified above may not necessarily be all of the important factors that could cause actual results to differ materially from those expressed in any forward-looking statement made by us, or on our behalf. Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We undertake no responsibility to publicly release the result of any revision of our forward-looking statements after the date they are made.

In addition, in certain places in this Quarterly Report on Form 10-Q, we refer to reports published by third parties that purport to describe trends or developments in the energy industry. The Company does so for the convenience of our stockholders and in an effort to provide information available in the market that will assist the Company’s investors to have a better understanding of the market environment in which the Company operates. However, the Company specifically disclaims any responsibility for the accuracy and completeness of such information and undertakes no obligation to update such information.

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

The following discussion and analysis should be read together with our condensed consolidated financial statements and the notes to those statements included elsewhere in this Quarterly Report on Form 10-Q and our consolidated financial statements and notes to those statements included in our 2016 Form 10-K.

During the first quarter of 2017, we modified the name of our “Offshore Products” segment to the “Offshore/Manufactured Products” segment given the higher proportional weighting of our shorter-cycle manufactured products (much of which is driven by land-based activity) to the total revenues generated by the segment. The Company has also provided supplemental disclosure below, and in Note 12, “Segments and Related Information,” with respect to product and service revenues generated by the Offshore/Manufactured Products segment, including project-driven products, short-cycle products, and other products and services. There have been no operational, reporting or other material changes related to the Offshore/Manufactured Products segment.

We provide a broad range of products and services to the oil and gas industry through our Offshore/Manufactured Products and Well Site Services business segments. Demand for our products and services is cyclical and substantially dependent upon activity levels in the oil and gas industry, particularly our customers’ willingness to invest capital in the exploration for and development of crude oil and natural gas reserves. Our customers’ capital spending programs are generally based on their cash flows and their outlook for near-term and long-term commodity prices, economic growth, commodity demand and estimates of resource production. As a result, demand for our products and services is largely sensitive to future expectations with respect to crude oil and natural gas prices.

A severe industry downturn started in the second half of 2014 and continued into 2017, driven by global economic uncertainties and high levels of global oil production. As shown in the table that follows, significant downward crude oil price volatility began in late 2014 with Intercontinental Exchange Brent (“Brent”) crude oil declining from an average of $110 per barrel in the second quarter of 2014 to an average of $34 per barrel in the first quarter of 2016 (a level last seen in 2004). The sustained material decrease in crude oil prices relative to 2014 is primarily attributable to high levels of global crude oil inventories resulting from significant production growth in the U.S. shale plays, the strengthening of the U.S. dollar relative to other currencies, and increased production by the Organization of Petroleum Exporting Countries (“OPEC”). OPEC demonstrated, throughout 2015 and through November of 2016 an unwillingness to modify production levels, as it had done in previous years, in an effort to protect its market share. These production increases were partially offset by growth in global crude oil demand. The combination of these factors caused a global supply and demand imbalance for crude oil which, along with concerns regarding the potential effects on energy demand stemming from the diminished growth outlook in China and other emerging markets, and supply increases related to the lifting of sanctions against Iran, resulted in materially lower crude oil prices. Non-OPEC production, particularly in the United States, began to decline in 2015 due to substantially reduced investment in drilling and completion activity triggered by lower crude oil prices leading to some recovery in crude oil prices in late 2016 and early 2017 relative to the crude oil price lows experienced in early 2016. On November 30, 2016, OPEC agreed to production cuts which should, over time, if the cuts are adhered to, result in further reductions in global crude oil inventories and a more favorable commodity price environment. In May 2017, OPEC agreed to extend these production cuts to March 2018. Brent crude oil prices averaged $50 per barrel in the second quarter of 2017, which is 9% above the second quarter 2016 average but is down 7% from the average in the first quarter of 2017. Similarly, the average price of West Texas Intermediate (“WTI”) was $48 per barrel in the second quarter of 2017, up 6% from the second quarter 2016 average of $45 per barrel but down 7% on a sequential quarter basis. The year-over-year improvement in oil prices was driven by the belief that OPEC and Russia, its key ally in the effort to stabilize the global crude oil market, would be successful in cutting their production. However, improvements in crude oil prices over the past twelve months rapidly translated into increased drilling activity in U.S. shale play developments in areas such as the Permian Basin, which is leading to higher domestic production. This increased shale driven activity has pressured crude oil prices again with the WTI price per barrel declining 9% between March 31, 2017 and July 24, 2017. Spending in these regions, which began to improve in the second half of 2016 in response to higher crude oil prices, has positively influenced the overall drilling and completion activity in these regions and, therefore, the activity of our Well Site Services segment as well as for short-cycle products within our Offshore/Manufactured Products segment in 2017. Expectations with respect to the longer-term price for Brent crude oil will continue to influence our customers’ spending related to global offshore drilling and development and, thus, a significant portion of the activity of our Offshore/Manufactured Products segment.

Recent WTI crude oil, Brent crude and natural gas pricing trends are as follows:

Demand for the products and services of our Offshore/Manufactured Products segment is driven by the longer-term outlook for commodity prices and changes in drilling and completion activity, both offshore and onshore. Demand for the equipment and services of our Well Site Services segment responds to shorter-term movements in crude oil and natural gas prices and, specifically, changes in North American drilling and completion activity given the spot contract nature of our operations coupled with shorter cycles between drilling a well and bringing it on production. Other factors that can affect our business and financial results include, but are not limited to, the general global economic environment, competitive pricing pressures and regulatory changes in the United States and international markets.

Our Offshore/Manufactured Products segment provides technology-driven, highly-engineered products and services for offshore oil and natural gas production systems and facilities, as well as certain products and services to the offshore and land-based drilling and completion markets. Approximately 60% of Offshore/Manufactured Products sales in 2016 were driven by our customers’ capital spending for offshore production systems and subsea pipeline infrastructure, repairs and, to a lesser extent, upgrades of existing offshore drilling rigs and construction of new offshore drilling rigs and vessels (referred to herein as “project-driven product revenue”). As a result, this segment has historically been particularly influenced by global deepwater drilling and production spending, which are driven largely by our customers’ longer-term outlook for crude oil and natural gas prices. Deepwater oil and gas development projects typically involve significant capital investments and multi-year development plans. As a result, such projects are generally undertaken by larger exploration, field development and production companies (primarily international oil companies (“IOCs”) and state-run national oil companies (“NOCs”)) using relatively conservative crude oil and natural gas pricing assumptions. We believe some of these deepwater projects once approved for development are, therefore, less susceptible to short-term fluctuations in the price of crude oil and natural gas given longer lead times associated with field development. However, the decline in crude oil prices that began in 2014 and continued into 2017, coupled with the relatively uncertain outlook around shorter-term and possibly longer-term pricing improvements have caused exploration and production companies to reevaluate their future capital expenditures in regards to these deepwater projects since they are expensive to drill and complete, have long lead times to first production and may be considered uneconomical relative to the risk involved. However, several development projects have been sanctioned in the first half of 2017 due to re-engineering of the projects and lower development costs, which led to an improvement in final investment decisions (“FID’s”) on these projects from the previous two years. Our bookings declined over the last two years, leading to substantially reduced backlog in 2017 relative to recent years. As a result, this segment’s project-driven revenue declined 58% from the first half of 2016 and accounted for only 35% of the total segment’s revenue in the first half of 2017. Shorter-cycle manufactured products sold to the land-based completions market are impacted by near-term fluctuations in commodity prices. For the six months ended June 30, 2017, sales of these shorter-cycle products (such as valves and elastomer products) for this segment increased 86% over the level reported in the same period last year due to the significant increase in U.S. land-based drilling and completion activity.

Our Offshore/Manufactured Products segment revenues and operating income declined at a slower pace over recent years than our Well Site Services segment given the high levels of backlog that existed at the beginning of 2014. Bidding and quoting activity, along with orders from customers, for our Offshore/Manufactured Products segment continued after 2014, albeit at a much slower pace. Reflecting the impact of customer (both IOCs and NOCs) delays and deferrals in approving major, capital intensive projects in light of the prolonged low commodity price environment, backlog in our Offshore/Manufactured Products segment decreased from $599 million at June 30, 2014 to $199 million at December 31, 2016. With a book-to-bill ratio of 1.0x in the first half of 2017, our backlog increased to $202 million at June 30, 2017 from December 31, 2016. The following table sets forth backlog for our Offshore/Manufactured Products segment as of the dates indicated (in millions).

In our Well Site Services segment, we predominantly provide completion services and, to a lesser extent, land drilling services. Our Completion Services business provides equipment and service personnel utilized in the completion and initial production of new and recompleted wells. Activity for the Completion Services business is dependent primarily upon the level and complexity of drilling, completion, and workover activity in the United States, including the Gulf of Mexico, and, to a lesser extent, Canada and the rest of the world. Well complexity has increased with the continuing transition to multi-well pads and the drilling of longer lateral wells along with the increased number of frac stages completed in horizontal wells. Demand for our Drilling Services operations is driven by land drilling activity in our primary drilling markets of the Permian Basin in West Texas, where we primarily drill oil wells, and the U.S. Rocky Mountain area, where we drill both liquids-rich and natural gas wells.

Demand for our Drilling Services and Completion Services businesses is correlated to changes in the drilling rig count in North America, as well as changes in the total number of wells drilled, total footage, and the number of drilled wells that are completed. The table below sets forth a summary of the average North American drilling rig count, as measured by Baker Hughes (a GE company), for the periods indicated.

The average North American rig count for the six months ended June 30, 2017 increased 423 rigs, or 71%, compared to the six months ended June 30, 2016, in response to the increase in crude oil prices discussed above.

Over the past several years, our industry experienced a shift in customer spending from natural gas exploration and development to crude oil and liquids-rich exploration and development in the North American shale plays utilizing horizontal drilling and completion techniques. The U.S. natural gas-related working rig count declined from approximately 810 rigs at the beginning of 2012 to 81 rigs in August of 2016, a more than 29 year low. According to rig count data published by Baker Hughes (a GE company), the U.S. oil rig count peaked in October 2014 at 1,609 rigs but has declined materially since late 2014 due to much lower crude oil prices, totaling 756 rigs as of June 30, 2017 (with the U.S. oil rig count having troughed at 316 rigs in May 2016, which was the lowest oil rig count during this current cyclical downturn). As of June 30, 2017, oil-directed drilling accounted for 80% of the total U.S. rig count – with the balance natural gas related. The total U.S. rig count has increased 536 rigs, or 133%, since troughing in May of 2016, largely due to decreased service costs and improved technologies applied in the shale play regions of the United States.

Exacerbating the steep declines in drilling activity experienced in 2015 and 2016, many of our exploration and production customers had deferred well completions. These deferred completions are referred to in the industry as drilled but uncompleted wells (or “DUCs”). Given our Well Site Services segment’s exposure to the level of completion activity, an increase in the number of DUCs will have a short-term negative impact on our results of operations relative to the rig count trends but over the longer-term should have a positive impact on the segment’s results as the wells are completed.

Reduced demand for our products and services, coupled with a reduction in the prices we charge our customers for our services has adversely affected our results of operations, cash flows and financial position since the second half of 2014. If the current pricing environment for crude oil and natural gas does not improve, or declines further, our customers may be required to further reduce their capital expenditures, causing additional declines in the demand for, and prices of, our products and services, which would adversely affect our results of operations, cash flows and financial position. Our customers have experienced a significant decline in their revenues and cash flows due to the commodity price declines, with many experiencing a significant reduction in liquidity. Several exploration and production companies declared bankruptcy during 2015 and 2016, or had to exchange equity for the forgiveness of debt, and others were forced to sell assets in an effort to preserve liquidity.

We continue to monitor the global economy, the prices of and demand for crude oil and natural gas, and the resultant impact on the capital spending plans and operations of our customers in order to plan and manage our business.

We manage and measure our business performance in two distinct operating segments: Well Site Services and Offshore/Manufactured Products. Selected financial information by business segment for the three and six months ended June 30, 2017 and 2016 is summarized below (dollars in thousands):

Three Months Ended June 30, 2017 Compared to Three Months Ended June 30, 2016

We reported a net loss for the three months ended June 30, 2017 of $14.2 million, or $0.28 per diluted share, which included $0.8 million ($0.6 million after-tax, or $0.01 per diluted share) of severance and other downsizing charges. Excluding these second quarter 2017 charges, the net loss would have been $13.6 million, or $0.27 per diluted share. These results compare to a net loss for the three months ended June 30, 2016 of $11.7 million, or $0.23 per diluted share, which included $1.1 million ($0.7 million after-tax, or $0.01 per diluted share) of severance and other downsizing charges. Excluding these second quarter 2016 charges, the net loss from continuing operations would have been $11.0 million, or $0.22 per diluted share.

Our consolidated results of operations reflect current industry trends and customer spending activities which are focused on growth in the U.S. shale play regions with weaker U.S. Gulf of Mexico and international activity. In addition, investments in deepwater markets globally has slowed since the start of the recent industry downturn in 2014.

Revenues. Consolidated revenues in the second quarter of 2017 decreased $4.4 million, or 3%, from the second quarter of 2016 due to declines in our Offshore/Manufactured Products segment, which were substantially offset by improvements in our Well Site Services segment. In the second quarter of 2017, revenues that were driven by U.S. shale play activity exceeded 50% of consolidated revenues.

Our Well Site Services segment revenues increased $29.0 million, or 70%, in the second quarter of 2017 from the prior-year quarter due to growth of both Completion Services and Drilling Services revenues. Our Completion Services revenues increased $21.1 million, or 57%, in the second quarter of 2017 compared to the second quarter of 2016, with the impact of a higher commodity price environment and lower service costs, which has led to increased U.S. land-based activity, partially offset by the timing of customer activity in the U.S. Gulf of Mexico and certain international markets. The number of Completion Services job tickets in the second quarter of 2017 increased 41% over the prior-year period and revenue per Completion Services job increased 12% year-over-year as a result of increased completions activity, a more favorable job mix and improved pricing. Our Drilling Services revenues increased $7.6 million to $11.5 million in the second quarter of 2017 from the second quarter of 2016 primarily as a result of increased utilization of our land drilling rigs from an average of 9% during the second quarter of 2016 to an average of 25% in the second quarter of 2017 and increased dayrates.

Our Offshore/Manufactured Products segment revenues decreased $33.1 million, or 25%, in the second quarter of 2017 compared to the second quarter of 2016 primarily as a result of a decline in demand for deepwater project-driven products (primarily subsea pipeline infrastructure, offshore production and drilling products), lower levels of service activities and a backlog position that has trended lower since mid-2014. These deepwater project-driven revenue declines were partially offset by increases in sales of our short-cycle products, which more than doubled year-over-year. Shorter-cycle products, such as elastomers and valves, have benefited from increased land-based drilling and completion activity in the United States. Bidding and quoting activity, along with orders from customers, for our Offshore/Manufactured Products segment continued, albeit at a much slower pace. Reflecting the impact of customer delays and deferrals in approving major, capital intensive projects in light of the prolonged low commodity price environment, backlog in our Offshore/Manufactured Products segment decreased from $340 million at December 31, 2015 to $199 million at December 31, 2016. With a book to bill ratio of 1.0x in the first half of 2017, our backlog increased to $202 million at June 30, 2017.

Cost of Sales and Services. Our consolidated cost of sales and services decreased $4.6 million, or 3%, in the second quarter of 2017 compared to the second quarter of 2016 as a result of decreased cost of sales and services at our Offshore/Manufactured Products segment of $26.5 million, or 27%, which was partially offset by a $21.9 million, or 58%, increase in cost of services at our Well Site Services segment. Consolidated gross profit as a percentage of revenues increased from 22% in the second quarter of 2016 to 23% in the second quarter of 2017, with gross margin expansion reported in both our operating segments.

Our Well Site Services segment cost of services increased $21.9 million, or 58%, in the second quarter of 2017 compared to the second quarter of 2016 as a result of a $15.4 million, or 45%, increase in Completion Services cost of services and a $6.5 million increase in costs in our Drilling Services business. These increases in cost of services, which are strongly correlated to the revenue increases in these businesses, reflect the increase in land-based activity in the United States. Costs increases included higher personnel costs from increased employee overtime and costs associated with headcount additions made during the current year. Our Well Site Services segment gross profit as a percentage of revenues improved from 7% in the second quarter of 2016 to 14% in the second quarter of 2017. Our Completion Services gross profit as a percentage of revenues increased from 7% in the second quarter of 2016 to 14% in the second quarter of 2017 primarily due to the significant increase in revenue levels. Our Drilling Services gross profit as a percentage of revenues improved from 10% in the second quarter of 2016 to 13% in the second quarter of 2017 primarily due to increased rig utilization and cost absorption.

Our Offshore/Manufactured Products segment cost of sales decreased $26.5 million, or 27%, in the second quarter of 2017 compared to the second quarter of 2016 reflecting the decrease in project-driven revenues. Gross profit as a percentage of revenues increased from 27% in the second quarter of 2016 to 29% in the second quarter of 2017 driven by the significant growth in sales of short-cycle products.

Selling, General and Administrative Expenses. Selling, general and administrative expenses decreased $1.0 million, or 3%, in the second quarter of 2017 from the prior-year quarter with the impact of 2016 cost reduction initiatives partially offset by higher incentive compensation accruals and reduced employee severance-related charges in the second quarter of 2017.

Depreciation and Amortization. Depreciation and amortization expense decreased $1.6 million, or 6%, in the second quarter of 2017 compared to the second quarter of 2016 primarily due to certain assets becoming fully depreciated since June 30, 2016 that, due to the downturn, have not been replaced coupled with overall lower levels of capital expenditures.

Other Operating (Income) Expense, Net. Other operating (income) expense, net moved from other operating income of $3.3 million in the second quarter of 2016 to other operating expense of $0.8 million in the second quarter of 2017, driven primarily by the impact of foreign currency exchange gains or losses recognized in the respective periods.

Operating Loss. Our consolidated operating loss increased from $17.2 million in the second quarter of 2016 to $18.5 million in the second quarter of 2017 primarily as a result of a decrease in operating income from our Offshore/Manufactured Products segment of $11.0 million due to a continued decline in offshore-related activity, offset by a decrease in operating loss of $11.1 million from our Well Site Services segment. Corporate expenses were $12.8 million in the second quarter of 2017, an increase of $1.4 million from the prior-year period due primarily to increased incentive compensation accruals.

Interest Expense and Interest Income. Net interest expense decreased $0.2 million, or 13%, in the second quarter of 2017 compared to the second quarter of 2016 primarily due to a reduction in amounts outstanding under the Revolving Credit Facility (defined below) partially offset by higher unused commitment fees paid to our lenders. Interest expense as a percentage of total debt outstanding increased from 6.4% in the second quarter of 2016 to 13.1% in the second quarter of 2017 due to an increased proportion of interest expense associated with unused commitment fees, lower average borrowings outstanding under the Revolving Credit Facility and non-cash amortization of debt issuance costs.

Income Tax Benefit. The income tax provision for interim periods is based on estimates of the effective tax rate for the entire fiscal year. The Company’s income tax provision for the three months ended June 30, 2017 was an income tax benefit of $5.1 million, or 26.2% of pre-tax losses, compared to an income tax benefit of $6.4 million, or 35.5% of pre-tax losses for the three months ended June 30, 2016. The lower effective tax rate benefit in the second quarter of 2017 was primarily attributable to a shift in the mix between domestic pre-tax losses and foreign pre-tax income compared to the prior-year period, and additional valuation allowances provided against net operating losses in certain domestic and foreign jurisdictions.

Other Comprehensive Income (Loss). Other comprehensive income was $5.1 million in the second quarter of 2017 compared to a loss of $8.9 million in the second quarter of 2016 due to fluctuations in foreign currency exchange rates compared to the U.S. dollar for certain of the international operations of our reportable segments. For the three months ended June 30, 2017 and 2016, currency translation adjustments recognized as a component of other comprehensive income (loss) were primarily attributable to the United Kingdom, Canada and Brazil. During the second quarter of 2017, the exchange rates for the British pound and the Canadian dollar strengthened compared to the U.S. dollar, while the Brazilian real weakened compared to the U.S. dollar during the same period. This compares to the second quarter of 2016, when the exchange rates for the British pound weakened compared to the U.S. dollar while the Brazilian real strengthened compared to the U.S. dollar. The British pound was impacted by the United Kingdom’s vote to exit the European Union in late June 2016.

We reported a net loss for the six months ended June 30, 2017 of $31.9 million, or $0.63 per diluted share, which included $1.6 million ($1.2 million after-tax, or $0.02 per diluted share) of severance and other downsizing charges. Excluding these charges in the first six months of 2017, the net loss would have been $30.7 million, or $0.61 per diluted share. These results compare to a net loss of $24.9 million, or $0.50 per diluted share for the six months ended June 30, 2016, which included $2.7 million ($1.7 million after-tax, or $0.03 per diluted share) of severance and other downsizing charges. Excluding these charges in the first six months of 2016, the net loss would have been $23.2 million, or $0.46 per diluted share.

Revenues. Consolidated revenues in the first six months of 2017 decreased $22.6 million, or 7%, from the first six months of 2016 due to declines in our Offshore/Manufactured Products segment, partially offset by improvements in our Well Site Services segment. In the first six months of 2017, approximately 50% of consolidated revenues were driven by U.S. shale play activity.

Our Well Site Services segment revenues increased $45.1 million, or 53%, in the first six months of 2017 compared to the prior-year period due to growth of both Completion Services and Drilling Services revenues. Our Completion Services revenues increased $28.8 million, or 37%, in the first six months of 2017 compared to the first six months of 2016, with the impact of a higher commodity price environment and lower service costs which has led to increased U.S. land-based activity, partially offset by lower customer activity in the U.S. Gulf of Mexico and certain international markets. The number of Completion Services job tickets in the first half of 2017 increased 19% over the prior-year period and revenue per Completion Services job increased 15% year-over-year as a result of increased completions activity, a more favorable job mix and improved pricing. Our Drilling Services revenues increased $16.3 million to $23.0 million in the first six months of 2017 from the first six months of 2016 due to higher utilization of our land drilling rigs, which increased from an average of 8% during the first six months of 2016 to an average of 25% in the first six months of 2017.

Our Offshore/Manufactured Products segment revenues decreased $67.7 million, or 26%, in the first six months of 2017 compared to the first six months of 2016 primarily as a result of a decline in demand for deepwater project-driven products (primarily subsea pipeline infrastructure, offshore production and drilling products), lower levels of service activities and a backlog position that has trended lower since mid-2014. These deepwater project-driven revenue declines were partially offset by an 86% increase in sales of our short-cycle products. Shorter-cycle products, such as elastomers and valves, have benefited from increased land-based drilling and completion activity in the United States. Bidding and quoting activity, along with orders from customers, for our Offshore/Manufactured Products segment continued, albeit at a much slower pace. Reflecting the impact of customer delays and deferrals in approving major, capital intensive projects in light of the prolonged low commodity price environment, backlog in our Offshore/Manufactured Products segment decreased from $340 million at December 31, 2015 to $199 million at December 31, 2016. With a book-to-bill ratio of 1.0x in the first half of 2017, our backlog increased to $202 million at June 30, 2017.

Cost of Sales and Services. Our consolidated cost of sales and services decreased $14.5 million, or 5%, in the first six months of 2017 compared to the first six months of 2016 as a result of decreased cost of sales and services at our Offshore/Manufactured Products segment of $47.7 million, or 26%, which was partially offset by a $33.3 million, or 40%, increase in cost of services at our Well Site Services segment. Consolidated gross profit as a percentage of revenues decreased from 23% in the first six months of 2016 to 22% in the first six months of 2017 with the impact of an 820 basis point improvement in gross margins within our Well Site Services segment offset by shift in the relative revenue contribution levels between the segments.

Our Well Site Services segment cost of services increased $33.3 million, or 40%, in the first six months of 2017 compared to the first six months of 2016 as a result of a $20.4 million, or 27%, increase in Completion Services cost of services and a $12.9 million increase in service costs in our Drilling Services business. These increases in cost of services, which are strongly correlated to the revenue increases in these businesses, reflect the increase in land-based activity in the United States. Costs increases included higher personnel costs from increased employee overtime and costs associated with headcount additions made during the first half of 2017. Our Well Site Services segment gross profit as a percentage of revenues improved from 3% in the first six months of 2016 to 11% in the first six months of 2017. Our Completion Services gross profit as a percentage of revenues increased from 4% in the first six months of 2016 to 11% in the first six months of 2017 primarily due to the increase in revenues. Our Drilling Services gross profit as a percentage of revenues improved from (11)% in the first six months of 2016 to 12% in the first six months of 2017 primarily due to increased rig utilization and cost absorption.

Our Offshore/Manufactured Products segment cost of sales decreased $47.7 million, or 26%, in the first six months of 2017 compared to the first six months of 2016 reflecting the decrease in project-driven revenues. Gross profit as a percentage of revenues was 30% in the first six months of 2017, consistent with the prior year level.

Selling, General and Administrative Expenses. Selling, general and administrative expenses decreased $3.3 million, or 5%, in the first six months of 2017 from the prior-year period primarily due to the impact of 2016 cost reduction initiatives partially offset by higher incentive compensation accruals and lower employee severance-related charges in the first six months of 2017.

Depreciation and Amortization. Depreciation and amortization expense decreased $4.1 million, or 7%, in the first six months of 2017 compared to the first six months of 2016 primarily due to certain assets becoming fully depreciated since June 30, 2016 that, due to the downturn, have not been replaced coupled with overall lower levels of capital expenditures.

Other Operating (Income) Expense, Net. Other operating (income) expense, net moved from other operating income of $2.7 million in the first six months of 2016 to other operating expense of $1.0 million in the first six months of 2017, reflecting primarily the impact of foreign currency exchange gains or losses recognized in the respective periods.

Operating Loss. Our consolidated operating loss increased from $37.3 million in the first six months of 2016 to $41.8 million in the first six months of 2017 primarily as a result of a decrease in operating income from our Offshore/Manufactured Products segment of $24.9 million due to a continued decline in offshore-related activity, partially offset by a decreased operating loss of $22.8 million from our Well Site Services segment. Corporate expenses were $24.9 million in the first six months of 2017, an increase of $2.5 million from the prior-year period due primarily to incentive compensation accruals.

Interest Expense and Interest Income. Net interest expense decreased $0.5 million, or 19%, in the first six months of 2017 compared to the first six months of 2016 primarily due to a reduction in amounts outstanding under the Revolving Credit Facility partially offset by higher unused commitment fees paid to our lenders. Interest expense as a percentage of total debt outstanding increased from 5.6% in the first six months of 2016 to 14.7% in the first six months of 2017 due to an increased proportion of interest expense associated with unused commitment fees, lower average borrowings outstanding under the Revolving Credit Facility and non-cash amortization of debt issuance costs.

Income Tax Benefit. The income tax provision for interim periods is based on estimates of the effective tax rate for the entire fiscal year. The Company’s income tax provision for the six months ended June 30, 2017 was an income tax benefit of $11.7 million, or 26.8% of pre-tax losses, compared to an income tax benefit of $14.5 million, or 36.7% of pre-tax losses for the six months ended June 30, 2016. The lower effective tax rate benefit in the first six months of 2017 was primarily attributable to a shift in the mix between domestic pre-tax losses and foreign pre-tax income compared to the prior-year period, and additional valuation allowances provided against net operating losses in certain domestic and foreign jurisdictions.

Other Comprehensive Income (Loss). Other comprehensive income was $8.6 million in the first six months of 2017 compared to a loss of $7.3 million in the first six months of 2016 due to fluctuations in foreign currency exchange rates compared to the U.S. dollar for certain of the international operations of our reportable segments. For the six months ended June 30, 2017 and 2016, currency translation adjustments recognized as a component of other comprehensive income (loss) were primarily attributable to the United Kingdom, Canada and Brazil. During the first half of 2017, the exchange rates for the British pound and the Canadian dollar strengthened compared to the U.S. dollar, while the Brazilian real weakened compared to the U.S. dollar during the same period. This compares to the first half of 2016, when exchange rates for the British pound weakened compared to the U.S. dollar while the Canadian dollar and Brazilian real strengthened compared to the U.S. dollar. The British pound was impacted by the United Kingdom’s vote to exit the European Union in late June 2016.

Our primary liquidity needs are to fund operating and capital expenditures which, in the past, have included expanding and upgrading our Offshore/Manufactured Products manufacturing facilities and equipment, replacing and increasing Completion Services assets, funding new product development, and general working capital needs. In addition, capital has been used to repay debt, fund our share repurchase program, and fund strategic business acquisitions. Our primary sources of funds have been cash flow from operations, proceeds from borrowings under the Revolving Credit Facility, and capital markets transactions.

The crude oil and natural gas industry is highly cyclical which may result in declines in the demand for, and prices of, our products and services or the inability or failure of our customers to meet their obligations to us. These adverse market conditions could require us to incur asset impairment charges, deferred tax valuation allowances and/or write down the value of our goodwill, and may otherwise adversely impact our results of operations and our cash flows and financial position.

Despite the weak market conditions, cash flows totaling $44.9 million were provided by continuing operations during the first six months of 2017 compared to $82.1 million provided by continuing operations during the same period of 2016. During the first six months of 2017, $24.6 million was provided from net working capital reductions, primarily due to decreases in receivables and inventories. During the first six months of 2016, $55.4 million was provided from net working capital reductions, also primarily due to decreases in receivables.

Cash used in investing activities during the first six months of 2017 was $25.9 million compared to $19.4 million used in investing activities during the first six months of 2016. Capital expenditures totaled $13.3 million and $18.4 million during the first six months of 2017 and 2016, respectively. During the first six months of 2017, we also invested $12.9 million within our Offshore/Manufactured Products segment to acquire complementary intellectual property and assets to expand our global crane manufacturing and service operations as well as our riser testing, inspection and repair service offerings.

After considering the $13.3 million invested during the first six months of 2017, we expect to spend between $35 million to $40 million in total capital expenditures during 2017, which compares to $30 million spent in 2016. Whether planned expenditures will actually be spent in 2017 depends on industry conditions, project approvals and schedules, vendor delivery timing, and careful monitoring of our levels of liquidity. We plan to fund these capital expenditures with available cash, internally generated funds, and borrowings under the Revolving Credit Facility. The foregoing capital expenditure forecast does not include any funds for strategic acquisitions, which the Company could pursue depending on the economic environment in our industry and the availability of transactions at prices deemed to be attractive to the Company.

At June 30, 2017, substantially all of our cash was held by our international subsidiaries. Our intent is to utilize at least a portion of these cash balances for future investment outside of the United States. Approximately $35 million of cash held by our international subsidiaries can be repatriated by us without triggering any incremental tax consequences.

During the six months ended June 30, 2017, net cash of $16.9 million was used in financing activities, primarily as a result of repurchases of $16.3 million of our common stock in the second quarter of 2017. This compares to $46.2 million of cash used in financing activities during the six months ended June 30, 2016, primarily as a result of repayment of outstanding debt under the Revolving Credit Facility.

We believe that cash on hand, cash flow from operations, and available borrowings under the Revolving Credit Facility will be sufficient to meet our liquidity needs in the coming twelve months. If our plans or assumptions change, or are inaccurate, or if we make further acquisitions, we may need to raise additional capital. Acquisitions have been, and our management believes acquisitions will continue to be, a key element of our business strategy. The timing, size or success of any acquisition effort and the associated potential capital commitments are unpredictable and uncertain. We may seek to fund all or part of any such efforts with proceeds from debt and/or equity issuances. Our ability to obtain capital for additional projects to implement our growth strategy over the longer term will depend upon our future operating performance, financial condition and, more broadly, on the availability of equity and debt financing. Capital availability will be affected by prevailing conditions in our industry, the global economy, the global financial markets and other factors, many of which are beyond our control. In addition, such additional debt service requirements could be based on higher interest rates and shorter maturities and could impose a significant burden on our results of operations and financial condition, and any issuance of additional equity securities could result in significant dilution to stockholders.

Share Repurchase Program. On July 29, 2015, the Company’s Board of Directors approved a new share repurchase program providing for the repurchase of up to $150.0 million of the Company’s common stock, which, following extension, was scheduled to expire on July 29, 2017. On July 26, 2017, our Board of Directors extended the share repurchase program for one year to July 29, 2018. During the second quarter of 2017, the Company repurchased 562 thousand shares of common stock under the program at a total cost of $16.3 million. The amount remaining under our share repurchase authorization as of June 30, 2017 was $120.5 million. Subject to applicable securities laws, such purchases will be at such times and in such amounts as the Company deems appropriate.

Credit Facility. The Company has a $600 million senior secured revolving credit facility (the “Revolving Credit Facility”) with an option to increase the maximum borrowings to $750 million subject to additional lender commitments prior to its maturity on May 28, 2019. As of June 30, 2017, we had $47.0 million in borrowings outstanding under the Credit Agreement (as defined below) and an additional $24.0 million of outstanding letters of credit, leaving $128.0 million available to be drawn under the Revolving Credit Facility. The total amount available to be drawn was less than the lender commitments as of June 30, 2017, due to the maximum leverage ratio covenant in the Credit Agreement which serves to limit borrowings. We expect our availability to continue to be limited by the maximum leverage ratio covenant in 2017 based upon our forecast of our trailing twelve-month EBITDA (as defined in the Credit Agreement and further discussed below).

The Revolving Credit Facility is governed by a Credit Agreement dated as of May 28, 2014, as amended, (the “Credit Agreement”) by and among the Company, the Lenders party thereto, Wells Fargo Bank, N.A., as administrative agent, the Swing Line Lender and an Issuing Bank; Royal Bank of Canada, as Syndication agent; and Compass Bank, as Documentation agent. Amounts outstanding under the Revolving Credit Facility bear interest at LIBOR plus a margin of 1.50% to 2.50%, or at a base rate plus a margin of 0.50% to 1.50%, in each case based on a ratio of the Company’s total leverage to EBITDA. During the first half of 2017, our applicable margin over LIBOR was 1.50%. We must also pay a quarterly commitment fee, based on our leverage ratio, on the unused commitments under the Credit Agreement. The unused commitment fee was 0.375% during the first half of 2017. Interest expense as a percentage of total debt outstanding increased from 5.6% in the first six months of 2016 to 14.7% in the first six months of 2017. The increase in the weighted average interest rate was attributable to an increased proportion of interest expense associated with unused commitment fees, lower average borrowings outstanding under the Revolving Credit Facility and non-cash amortization of debt issuance costs.

The Credit Agreement contains customary financial covenants and restrictions. Specifically, we must maintain an interest coverage ratio, defined as the ratio of consolidated EBITDA to consolidated interest expense, of at least 3.0 to 1.0 and a maximum leverage ratio, defined as the ratio of total debt to consolidated EBITDA, of no greater than 3.25 to 1.0. Each of the factors considered in the calculations of these ratios are defined in the Credit Agreement. EBITDA and consolidated interest, as defined, exclude goodwill impairments, losses on extinguishment of debt, debt discount amortization, and other non-cash charges. As of June 30, 2017, we were in compliance with our debt covenants and expect to continue to be in compliance during the remainder of 2017. Borrowings under the Credit Agreement are secured by a pledge of substantially all of our assets and the assets of our domestic subsidiaries. Our obligations under the Credit Agreement are guaranteed by our significant domestic subsidiaries.

Our total debt represented 4.2% of our combined total debt and stockholders’ equity at June 30, 2017 compared to 3.7% at December 31, 2016.

For a discussion of the critical accounting policies and estimates that we use in the preparation of our condensed consolidated financial statements, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our 2016 Form 10-K. These estimates require significant judgments, assumptions and estimates. We have discussed the development, selection, and disclosure of these critical accounting policies and estimates with the audit committee of our Board of Directors. There have been no material changes to the judgments, assumptions, and estimates upon which our critical accounting estimates are based. For a discussion of recent accounting pronouncements, see Note 2, “Recent Accounting Pronouncements.”

As of June 30, 2017, we had no off-balance sheet arrangements as defined in Item 303(a)(4)(ii) of Regulation S-K.

Market risk refers to the potential losses arising from changes in interest rates, foreign currency fluctuations and exchange rates, equity prices, and commodity prices, including the correlation among these factors and their volatility.

Our principal market risks are our exposure to changes in interest rates and foreign currency exchange rates. We enter into derivative instruments only to the extent considered necessary to meet risk management objectives and do not use derivative contracts for speculative purposes.

We have a revolving credit facility that is subject to the risk of higher interest charges associated with increases in interest rates. As of June 30, 2017, we had floating-rate obligations totaling $47.0 million drawn under the Revolving Credit Facility. These floating-rate obligations expose us to the risk of increased interest expense in the event of increases in short-term interest rates. If the floating interest rates increased by 1% from June 30, 2017 levels, our consolidated interest expense would increase by a total of approximately $0.5 million annually.

Our operations are conducted in various countries around the world and we receive revenue from these operations in a number of different currencies. As such, our earnings are subject to movements in foreign currency exchange rates when transactions are denominated in (i) currencies other than the U.S. dollar, which is our functional currency, or (ii) the functional currency of our subsidiaries, which is not necessarily the U.S. dollar. In order to mitigate the effects of foreign currency exchange rate risks in areas outside of the United States (primarily in our Offshore/Manufactured Products segment), we generally pay a portion of our expenses in local currencies and a substantial portion of our contracts provide for collections from customers in U.S. dollars. During the six months ended June 30, 2017, our reported foreign currency exchange losses were $1.0 million and are included in “Other operating (income) expense, net” in the Consolidated Statements of Operations. In order to reduce our exposure to fluctuations in foreign currency exchange rates, we may enter into foreign currency exchange agreements with financial institutions. As of June 30, 2017 and December 31, 2016, we had outstanding foreign currency forward purchase contracts with notional amounts of $2.2 million related to expected cash flows denominated in Euros.

Our accumulated other comprehensive loss, reported as a component of stockholders’ equity, decreased from $70.3 million at December 31, 2016 to $61.7 million at June 30, 2017, as a result of currency exchange rate differences. Our accumulated other comprehensive loss is primarily related to fluctuations in foreign currency exchange rates compared to the U.S. dollar which are used to translate certain of the international operations of our reportable segments. For the six months ended June 30, 2017, currency translation adjustments recognized as a component of other comprehensive income were primarily attributable to the United Kingdom, Canada and Brazil. As of June 30, 2017, the exchange rates for the British pound and the Canadian dollar compared to the U.S. dollar strengthened by 5% and 3%, respectively, compared to the exchange rates at December 31, 2016, while the Brazilian Real compared to the U.S. dollar weakened by 2% during the same period, resulting in other comprehensive income of $8.6 million reported for the six months ended June 30, 2017.

As of the end of the period covered by this Quarterly Report on Form 10-Q, we carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e)) of the Exchange Act. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Commission. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of June 30, 2017 at the reasonable assurance level.

During the six months ended June 30, 2017, there were no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act), which have materially affected our internal control over financial reporting, or are reasonably likely to materially affect our internal control over financial reporting.

The information with respect to this Item 1 is set forth under Note 13, “Commitments and Contingences.”

“Part I, Item 1A. Risk Factors” of our 2016 Form 10-K includes a detailed discussion of our risk factors. The risks described in this Quarterly Report on Form 10-Q and our 2016 Form 10-K are not the only risks we face. Additional risks and uncertainties not currently known to us, or that we currently deem to be immaterial, also may materially adversely affect our business, financial condition or future results. There have been no material changes to our risk factors as set forth in our 2016 Form 10-K.

The exhibits required to be filed by Item 6. are set forth in the Exhibit Index accompanying this Quarterly Report on Form 10-Q.

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	76-0476605
(State or other jurisdiction of	(I.R.S. Employer
incorporation or organization)	Identification No.)

Three Allen Center, 333 Clay Street, Suite 4620,	77002
Houston, Texas	(Zip Code)
(Address of principal executive offices)

Large accelerated filer [X]	Accelerated filer [ ]

Non-accelerated filer [ ] (Do not check if a smaller reporting company)	Smaller reporting company [ ]

	Emerging growth company [ ]

	Page No.
Part I -- FINANCIAL INFORMATION

Item 1. Financial Statements:

Condensed Consolidated Financial Statements
Unaudited Consolidated Statements of Operations	3
Unaudited Consolidated Statements of Comprehensive Loss	4
Consolidated Balance Sheets	5
Unaudited Consolidated Statement of Stockholders’ Equity	6
Unaudited Consolidated Statements of Cash Flows	7
Notes to Unaudited Condensed Consolidated Financial Statements	8 – 16

Cautionary Statement Regarding Forward-Looking Statements	17 – 18

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	18 – 30

Item 3. Quantitative and Qualitative Disclosures About Market Risk	30

Item 4. Controls and Procedures	31

Part II -- OTHER INFORMATION

Item 1. Legal Proceedings	32

Item 1A. Risk Factors	32

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	32

Item 3. Defaults upon Senior Securities	32

Item 4. Mine Safety Disclosures	32

Item 5. Other Information	32

Item 6. Exhibits	32

Signature Page	33

Shares of common stock outstanding – December 31, 2016	51,374,361
Restricted stock awards, net of forfeitures	426,816
Shares withheld for taxes on vesting of restricted stock awards and transferred to treasury	(143,705	)
Purchase of treasury stock	(561,765	)
Shares of common stock outstanding – June 30, 2017	51,095,707

	Average Price ⁽¹⁾
	WTI		Brent		Henry Hub
	Crude		Crude		Natural Gas
Quarter Ended	(per bbl)		(per bbl)		(per mmBtu)
June 30, 2017	$	48.14	$	49.59	$	3.08
March 31, 2017		51.62		53.59		3.02
December 31, 2016		49.14		49.11		3.04
September 30, 2016		44.85		45.80		2.88
June 30, 2016		45.46		45.57		2.15
March 31, 2016		33.35		33.84		1.99
December 31, 2015		41.94		43.56		2.12
September 30, 2015		46.49		50.44		2.76
June 30, 2015		57.85		61.65		2.75
March 31, 2015		48.49		53.98		2.90
December 31, 2014		73.21		76.43		3.78
September 30, 2014		97.87		101.90		3.96
June 30, 2014		103.35		109.69		4.61
March 31, 2014		98.68		108.14		5.18

	Common Stock		Additional Paid-In Capital		Retained Earnings			Accumulated Other Comprehensive Loss			Treasury Stock			Total Stockholders' Equity
Balance, December 31, 2016	$	623	$	731,562	$	1,133,473		$	(70,300	)	$	(591,051	)	$	1,204,307
Net loss		–		–		(31,924	)		–			–			(31,924	)
Currency translation adjustments (excluding intercompany advances)		–		–		–			8,149			–			8,149
Currency translation adjustments on intercompany advances		–		–		–			484			–			484
Stock-based compensation expense-
Restricted stock		4		10,243		–			–			–			10,247
Stock options		–		707		–			–			–			707
Stock repurchases		–		–		–			–			(16,283	)		(16,283	)
Surrender of stock to pay taxes on restricted stock awards		–		–		–			–			(5,200	)		(5,200	)
Balance, June 30, 2017		627		742,512		1,101,549			(61,667	)		(612,534	)		1,170,487

	Backlog as of
Year	March 31		June 30		September 30		December 31
2017	$	204	$	202
2016	$	306	$	268	$	203	$	199
2015	$	474	$	409	$	394	$	340
2014	$	578	$	599	$	543	$	490

Period	Total Number of Shares Purchased ⁽¹⁾	Average Price Paid per Share ⁽¹⁾	Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Approximate Dollar Value of Shares That May Yet Be Purchased Under the Plans or Programs ⁽²⁾
April 1 through April 30, 2017	99,230	$30.17	98,970	$133,843,180
May 1 through May 31, 2017	311,189	29.08	310,647	124,810,106
June 1 through June 30, 2017	152,321	28.04	152,148	120,544,560
Total	562,740	$28.99	561,765


Date:	July 31, 2017	By	/s/ LLOYD A. HAJDIK
			Lloyd A. Hajdik
			Executive Vice President, Chief Financial Officer and
			Treasurer (Duly Authorized Officer and Principal Financial Officer)

Exhibit No.		Description

3.1	—	Amended and Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.1 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2000, as filed with the Commission on March 30, 2001 (File No. 001-16337)).

3.2	—	Third Amended and Restated Bylaws (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K, as filed with the Commission on March 13, 2009 (File No. 001-16337)).

3.3	—	Certificate of Designations of Special Preferred Voting Stock of Oil States International, Inc. (incorporated by reference to Exhibit 3.3 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2000, as filed with the Commission on March 30, 2001 (File No. 001-16337)).

10.1	—	Second Amended and Restated 2001 Equity Participation Plan effective January 1, 2017 (incorporated by reference to Exhibit 10.2 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2016, as filed with the Commission on February 17, 2017 (File No. 001-16337)).

10.2	—	Annual Incentive Compensation Plan, dated January 1, 2017 (incorporated by reference to Exhibit 10.4 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2016, as filed with the Commission on February 17, 2017 (File No. 001-16337)).

31.1*	—	Certification of Chief Executive Officer of Oil States International, Inc. pursuant to Rules 13a-14(a) or 15d-14(a) under the Securities Exchange Act of 1934, as amended.

31.2*	—	Certification of Chief Financial Officer of Oil States International, Inc. pursuant to Rules 13a-14(a) or 15d-14(a) under the Securities Exchange Act of 1934, as amended.

32.1**	—	Certification of Chief Executive Officer of Oil States International, Inc. pursuant to Rules 13a-14(b) or 15d-14(b) under the Securities Exchange Act of 1934, as amended.

32.2**	—	Certification of Chief Financial Officer of Oil States International, Inc. pursuant to Rules 13a-14(b) or 15d-14(b) under the Securities Exchange Act of 1934, as amended.

101.INS*	—	XBRL Instance Document

101.SCH*	—	XBRL Taxonomy Extension Schema Document

101.CAL*	—	XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF*	—	XBRL Taxonomy Extension Definition Linkbase Document.

101.LAB*	—	XBRL Taxonomy Extension Label Linkbase Document

101.PRE*	—	XBRL Taxonomy Extension Presentation Linkbase Document