UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-Q

 

(Mark One)

[X]

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

For the quarterly period ended September 30, 2016

 

OR

 

[ ]

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

For the transition period from         to

 

Commission file number: 001-16337

 

OIL STATES INTERNATIONAL, INC.

---

 (Exact name of registrant as specified in its charter)

 

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)

 

(713) 652-0582

 

 

(Registrant’s telephone number, including area code)

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

YES [ X ]

NO [  ]

 

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

YES [X]

NO [  ]

 

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

(Check one):

 

Large Accelerated Filer [X]	Accelerated Filer [  ]
Non-Accelerated Filer [  ] (Do not check if a smaller reporting company)	Smaller Reporting Company [  ]

          

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

YES [  ]

NO [X]

 

The Registrant had 51,374,790 shares of common stock, par value $0.01, outstanding as of October 25, 2016.

 

 

OIL STATES INTERNATIONAL, INC.

 

INDEX

	Page No.
Part I -- FINANCIAL INFORMATION
Item 1.  Financial Statements:
Condensed Consolidated Financial Statements
Unaudited Condensed Consolidated Statements of Operations	3
Unaudited Condensed Consolidated Statements of Comprehensive (Loss) Income	4
Consolidated Balance Sheets	5
Unaudited Condensed Consolidated Statements of Cash Flows	6
Unaudited Condensed Consolidated Statement of Stockholders’ Equity	7
Notes to Unaudited Condensed Consolidated Financial Statements	8 – 16
Cautionary Statement Regarding Forward-Looking Statements	17
Item 2.   Management’s Discussion and Analysis of Financial Condition and Results of Operations	17 – 28
Item 3.   Quantitative and Qualitative Disclosures About Market Risk	28 – 29
Item 4.   Controls and Procedures	29
Part II -- OTHER INFORMATION
Item 1.     Legal Proceedings	30
Item 1A.  Risk Factors	30
Item 2.     Unregistered Sales of Equity Securities and Use of Proceeds	30
Item 4.    Mine Safety Disclosures	30
Item 5.    Other Information	30
Item 6.    Exhibits	31
Signature Page	32

 

 

PART I -- FINANCIAL INFORMATION

 

ITEM 1. Financial Statements

 

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

 

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In Thousands, Except Per Share Amounts)

 

 

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

 

 

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

 

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE (LOSS) INCOME

(In Thousands)

 

 

 

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

 

 

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

 

CONSOLIDATED BALANCE SHEETS

(In Thousands, Except Share Amounts)

 

 

 

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

 

 

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

 

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In Thousands)

 

 

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

 

 

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

 

UNAUDITED CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY

(In Thousands)

 

 

 

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

 

 

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

 

NOTES TO UNAUDITED CONDENSED CONSOLIDATED

FINANCIAL STATEMENTS

 

 

 

 

 

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

 

NOTES TO UNAUDITED CONDENSED CONSOLIDATED

FINANCIAL STATEMENTS

(Continued)

 

 

 

 

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

 

NOTES TO UNAUDITED CONDENSED CONSOLIDATED

FINANCIAL STATEMENTS

(Continued)

 

 

 

 

 

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

 

NOTES TO UNAUDITED CONDENSED CONSOLIDATED

FINANCIAL STATEMENTS

(Continued)

 

 

 

 

Cautionary Statement Regarding Forward-Looking Statements

 

This Quarterly Report on Form 10-Q and other statements we make contain “forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 (the Exchange Act). The Private Securities Litigation Reform Act of 1995 provides safe harbor provisions for forward-looking information. “Forward-looking statements" can be identified by the use of forward-looking terminology including "may," "expect," "anticipate," "estimate," "continue," "believe," or other similar words. 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 II, Item 1A. Risk Factors” in this report and "Part I, Item 1A. Risk Factors" and the financial statement line item discussions set forth in "Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations" included in our 2015 Form 10-K filed with the Commission on February 22, 2016. Should one or more of these risks or uncertainties materialize, or should the assumptions prove incorrect, actual results may differ materially from those expected, estimated or projected. Our management believes these forward-looking statements are reasonable. However, you should not place undue reliance on these forward-looking statements, which are based only on our current expectations and are not guarantees of future performance. All subsequent written and oral forward-looking statements attributable to us or to persons acting on our behalf are expressly qualified in their entirety by the foregoing. Forward-looking statements speak only as of the date they are made, and we undertake no obligation to publicly update or revise any of them in light of new information, future events or otherwise.

 

In addition, in certain places in this quarterly report, 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 in 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 2015 Form 10-K.

 

Macroeconomic Environment

 

We are a technology-focused, energy services company. We provide a broad range of products and services to the oil and gas industry through our offshore 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 expectations with respect to crude oil and natural gas prices. 

 

Over the past two years, crude oil prices have been volatile, driven by global economic uncertainties, the level of global production, and inadequate regional well site transportation infrastructure. As shown in the table below, significant downward crude oil price volatility began early in the fourth quarter of 2014 and has continued to date in 2016 – with Intercontinental Exchange Brent (Brent) crude oil averaging approximately $48 per barrel over the most recent seven quarters (53)% below the third quarter 2014 average). In the third quarter of 2016, Brent crude oil averaged $46 per barrel, which compares to $102 per barrel during the same quarter in 2014. The sustained, material decrease in crude oil prices since 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 the Organization of Petroleum Exporting Companies (OPEC) increasing its production. OPEC demonstrated throughout 2015, and until recently, an unwillingness to modify production levels, as it has done in previous years, in an effort to protect its market share. These production increases have been 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 the anticipation of potential supply increases related to the lifting of sanctions against Iran (sanctions were lifted in January 2016), resulted in materially lower crude oil prices in 2015 and the first nine months of 2016. Additionally, the vote in June 2016 by the United Kingdom to leave the European Union raised concerns around the global demand outlook for crude oil. Non-OPEC production, particularly in the United States, began to decline in 2015 due to substantially reduced investment in drilling and completion activity leading to some crude oil price improvements in recent quarters. The average price of West Texas Intermediate (WTI) crude oil increased to $45 per barrel in the third quarter of 2016 from $42 per barrel in the fourth quarter of 2015. These data points compare to an average price of $45 per barrel for WTI crude oil over the most recent seven calendar quarters (54% below the third quarter 2014 average). The magnitude of the supply/demand imbalance, and the resultant build in global crude oil inventories, has created a market concern that crude oil prices could decline further or remain at their lower levels for the foreseeable future. The current and expected price for WTI crude oil will continue to influence our customers’ spending in U.S. shale play developments, such as the Permian, Bakken, Niobrara, and Eagle Ford basins. Spending in these regions will influence the overall drilling and completion activity in the area and, therefore, the activity of our well site services segment. Expectations with respect to the price for Brent crude oil will continue to influence our customers’ spending related to global offshore drilling and development and, thus, the activity of our offshore products segment.

 

 

Given the historical volatility of crude oil prices, there remains a degree of risk that prices could remain at their current levels or deteriorate further due to relatively high levels of domestic crude oil production (albeit U.S. production has been and continues to decline), slowing growth rates in various global regions, and/or the potential for ongoing supply/demand imbalances. Conversely, if the global supply of crude oil were to decrease due to reduced capital investment by our customers (which is occurring) or government instability in a major oil-producing nation, and energy demand were to continue to increase in the United States and India, and China’s outlook for growth improves, a recovery in WTI and Brent crude oil prices could occur. In any event, crude oil price improvements will depend upon a rebalancing of global supply and demand, with a corresponding reduction in global inventories, the timing of which is difficult to predict. If commodity prices do not improve, or decline further, demand for our products and services could continue to be weak or could decline further.

 

Prices for natural gas in the United States averaged $2.88 per mmBtu in the third quarter of 2016, up 34% from the prior quarter average and relatively flat with the prior-year quarter average of $2.76 per mmBtu. This recent improvement in pricing reflects the impact of declining production and increased demand for natural gas to fuel electricity generation. While natural gas prices have improved, a milder winter this year compared to last year resulted in an increase in natural gas inventories in the United States from 4% above the 5-year average as of September 30, 2015 to 6% above the 5-year average as of September 30, 2016. Customer spending in the natural gas shale plays has been limited due to associated natural gas being produced from unconventional oil wells in North America and the recent commissioning of a number of new, large LNG export facilities around the world. As a result of natural gas supply growth outpacing demand growth in the United States in recent years, natural gas prices continue to be weak and are expected to remain below levels considered economical for new investments in certain natural gas fields. If natural gas production growth surpasses demand growth in the United States, and/or if the supply of natural gas were to increase, whether from conventional or unconventional production or associated natural gas production from oil wells, prices for natural gas could remain depressed for an extended period of time and could result in fewer rigs drilling for natural gas.

 

 

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

 

		Average Price (1)
		WTI				Brent				Henry Hub
Quarter		Crude				Crude				Natural Gas
Ended		(per bbl)				(per bbl)				(per mmBtu)
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

 

(1)

Source: U.S. Energy Information Administration (EIA). As of October 24, 2016, WTI crude oil, Brent crude and natural gas traded at approximately $50.18 per barrel, $49.80 per barrel and $2.78 per mmBtu, respectively.

 

Overview

 

Demand for the products and services of our offshore products segment is driven primarily by the longer-term outlook for commodity prices. Demand for 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 U.S. and international markets.

 

Our offshore products segment provides 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 drilling market. Sales of our offshore products and services depend primarily upon our customers’ capital spending for offshore production systems and subsea pipelines, repairs and, to a lesser extent, upgrades of existing offshore drilling rigs and construction of new offshore drilling rigs and vessels. In this segment, we are 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. Such projects are generally undertaken by larger exploration, field development and production companies using relatively conservative crude oil and natural gas pricing assumptions. We believe some of these deepwater projects 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 has persisted since late 2014 and 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 given that certain of these deepwater projects are expensive to drill and complete and may become uneconomical relative to the risk involved. In addition, shorter-cycle product sales (such as valves and elastomer products) and services for this segment declined in 2015 and 2016; however, demand for our elastomer products has increased in the third quarter compared to levels of demand experienced in the first half of 2016.      

 

Bidding and quoting activity, along with orders from customers, for our offshore products segment continued during the first nine months of 2016, albeit at a much slower pace. Accordingly, backlog in our offshore products segment decreased to $203 million at September 30, 2016, from $268 million at June 30, 2016 and $340 million at December 31, 2015, due to project deferrals and delays in award timing resulting from the continued depressed commodity price environment. Our offshore products backlog totaled $394 million at September 30, 2015.

 

Our well site services segment is primarily affected by drilling and completion activity in the United States, including the Gulf of Mexico, and, to a lesser extent, Canada and the rest of the world. U.S. drilling and completion activity and, thus, our well site services segment results, are especially sensitive to near-term fluctuations in commodity prices and have, therefore, been significantly negatively affected by the material decline in crude oil prices from 2014 to the current date.

 

 

Over the past years, our industry has experienced a shift in 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. According to rig count data published by Baker Hughes Incorporated, 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 425 rigs as of September 30, 2016 (with the U.S. oil rig count bottoming at 316 rigs in May 2016, which was the lowest oil rig count during this current cyclical downturn). As of September 30, 2016, the oil-directed drilling accounted for slightly over 80% of the total U.S. rig count – with the balance natural gas related. 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. Although the U.S. land rig count has increased 120 rigs, or 32%, since troughing in May of 2016, activity continues to remain at historically low levels. Unless commodity prices continue to gradually improve, we expect that the rig count and demand from our customers for our well site services will continue to remain low in the near term.

 

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 throughout North America. 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 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 land drilling 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 expected to be drilled, total footage expected to be drilled, and the number of drilled wells that are completed. The table below sets forth a summary of North American rig activity, as measured by Baker Hughes Incorporated, for the periods indicated.

 

		Average Drilling Rig Count
		Three Months Ended September 30,								Nine Months Ended September 30,
		2016				2015				2016				2015
U.S. Land – Oil			375				635				370				783
U.S. Land – Natural gas and other			87				198				90				230
U.S. Offshore			18				32				23				38
Total United States.			480				865				483				1,051
Canada			121				191				112				200
Total North America			601				1,056				595				1,251

 

The average North American rig count for the nine months ended September 30, 2016 fell 656 rigs, or 52%, compared to the nine months ended September 30, 2015, in response to sustained impact of significantly lower crude oil and natural gas prices from the levels experienced in 2014.

 

Exacerbating the steep declines in drilling activity, many of our exploration and production customers have been and continue to defer well completions, although a few of our customers have begun to complete their backlog of uncompleted wells. These deferred completions are referred to in the industry as drilled but uncompleted wells (or DUCs). Motivation on the part of our customers to defer completions is generally driven by the need to preserve cash in a weak commodity price environment and/or the desire to produce reserves at a later date with expectations that commodity prices will improve and/or completion costs will continue to decline. Given our well site services segment’s exposure to the level of completion activity, an increase in the number of DUCs will have a negative impact on our results of operations.

 

 

The reduced demand for our products and services, coupled with a reduction in the prices we charge our customers, particularly customers of our well site services business segment, has adversely affected our results of operations, cash flows and financial position as of and for the nine months ended September 30, 2016. If the current pricing environment for crude oil and natural gas continues, our customers may be required to further reduce their capital expenditures, causing further 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 and the fact that, due to the passage of time, many customers have less production hedged and, thus, are receiving spot prices for a greater percentage of their production. As a result of this industry downturn, many customers had experienced a significant reduction in liquidity with challenges accessing the capital and debt markets through the end of 2015. However, during the first nine months of 2016, access to the capital and debt markets has improved for certain customers. There have been several exploration and production companies who have declared bankruptcy, or have had to exchange equity for the forgiveness of debt, and others who have been forced to sell assets in an effort to preserve liquidity. A continuation of these adverse conditions could affect certain of our customers’ ability to pay or otherwise perform on their obligations to us. 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, or their insolvency or liquidation, could require us to incur asset impairment charges, 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.

 

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 our business. After considering the $23.9 million invested during the first nine months of 2016, we expect capital expenditures to total between $35 to $40 million for fiscal 2016 to upgrade and maintain our offshore products facilities and completion services equipment and to fund various other capital spending projects. We plan to fund our capital expenditures with available cash, internally generated funds, and borrowings under our revolving credit facility. In our well site services segment, we continue to monitor industry capacity additions and will make future capital expenditure decisions based on our evaluation of both the market outlook and industry fundamentals.

 

 

Consolidated Results of Operations

 

We manage and measure our business performance in two distinct operating segments: well site services and offshore products. Selected financial information by business segment for the three and nine months ended September 30, 2016 and 2015 is summarized below (dollars in millions):

 

 

		Three Months Ended September 30,																Nine Months Ended September 30,
										Variance																Variance
										2016 vs. 2015																2016 vs. 2015
		2016				2015				$				%				2016				2015				$				%
Revenues
Well site services -
Completion services		$	39.0			$	66.7			$	(27.7	)			(42	)%		$	116.8			$	254.3			$	(137.5	)			(54	)%
Drilling services			7.3				16.5				(9.2	)			(56	)%			14.0				56.9				(42.9	)			(75	)%
Total well site services			46.3				83.2				(36.9	)			(44	)%			130.8				311.2				(180.4	)			(58	)%
Offshore products			132.7				175.7				(43.0	)			(24	)%			393.7				554.3				(160.6	)			(29	)%
Total		$	179.0			$	258.9			$	(79.9	)			(31	)%		$	524.5			$	865.5			$	(341.0	)			(39	)%
Product and service costs
Well site services -
Completion services		$	36.9			$	52.5			$	(15.6	)			(30	)%		$	111.7			$	189.5			$	(77.8	)			(41	)%
Drilling services			7.0				14.0				(7.0	)			(50	)%			14.4				46.4				(32.0	)			(69	)%
Total well site services			43.9				66.5				(22.6	)			(34	)%			126.1				235.9				(109.8	)			(47	)%
Offshore products			91.9				122.1				(30.2	)			(25	)%			274.9				385.1				(110.2	)			(29	)%
Total		$	135.8			$	188.6			$	(52.8	)			(28	)%		$	401.0			$	621.0			$	(220.0	)			(35	)%
Gross margin
Well site services -
Completion services		$	2.1			$	14.2			$	(12.1	)			(85	)%		$	5.1			$	64.8			$	(59.7	)			(92	)%
Drilling services			0.3				2.5				(2.2	)			(88	)%			(0.4	)			10.5				(10.9	)			(104	)%
Total well site services			2.4				16.7				(14.3	)			(86	)%			4.7				75.3				(70.6	)			(94	)%
Offshore products			40.8				53.6				(12.8	)			(24	)%			118.8				169.2				(50.4	)			(30	)%
Total		$	43.2			$	70.3			$	(27.1	)			(39	)%		$	123.5			$	244.5			$	(121.0	)			(49	)%
Gross margin as a percentage of revenues
Well site services -
Completion services			5	%			21	%											4	%			25	%
Drilling services			4	%			15	%											(3	)%			18	%
Total well site services			5	%			20	%											4	%			24	%
Offshore products			31	%			31	%											30	%			31	%
Total			24	%			27	%											24	%			28	%

 

Three Months Ended September 30, 2016 Compared to Three Months Ended September 30, 2015

 

Net loss from continuing operations attributable to the Company for the three months ended September 30, 2016 was $10.8 million, or $0.22 per diluted share, which included $2.0 million ($1.3 million after-tax, or $0.03 per diluted share) of severance and other downsizing charges. Excluding these third quarter 2016 charges, the net loss from continuing operations would have been $9.5 million, or $0.19 per diluted share. These results compare to net income from continuing operations attributable to the Company of $1.7 million, or $0.03 per diluted share, reported for the three months ended September 30, 2015, which included a higher effective tax rate driven primarily by a $3.2 million, or $0.06 per diluted share, tax valuation allowance recorded against certain of the Company’s deferred tax assets related to tax loss carryforwards and $0.7 million ($0.6 million after-tax, or $0.01 per diluted share) of severance-related costs. Excluding the higher effective tax rate and severance costs, net income from continuing operations for the third quarter of 2015 would have been $5.6 million, or $0.11 per diluted share.

 

 

Revenues. Consolidated revenues in the third quarter of 2016 declined $79.9 million, or 31%, from the level reported in the third quarter of 2015.

 

Our well site services segment revenues decreased $36.9 million, or 44%, in the third quarter of 2016 compared to the prior-year quarter due to decreases in both completion services and drilling services revenues. Our completion services revenues decreased $27.7 million, or 42%, in the third quarter of 2016 compared to the third quarter of 2015, primarily due to a 49% decrease in the number of service tickets completed as a result of continued extreme competitive pressures and depressed activity levels. The revenue decline was partially offset by a 15% year-over-year increase in revenue per completion service job primarily driven by an increase in the proportion of longer-duration jobs in international markets and longer-term project work in the U.S. Gulf of Mexico during the third quarter of 2016. Our drilling services revenues decreased $9.2 million, or 56%, in the third quarter of 2016 compared to the third quarter of 2015 primarily as a result of significantly decreased utilization of our land drilling rigs from an average of 33% during the third quarter of 2015 to an average of 15% in the third quarter of 2016 due to the continued weak commodity price environment.

 

Our offshore products segment revenues decreased $43.0 million, or 24%, in the third quarter of 2016 compared to the third quarter of 2015 primarily as a result of lower contributions across most of the segment’s product and service lines, especially production-related and drilling products, and lower levels of service activities, and a backlog position that has trended lower since mid-2014, partially offset by improved elastomer product and subsea pipeline product revenues. Bidding and quoting activity, along with orders from customers, for our offshore products segment continued during the third quarter of 2016, albeit at a much slower pace.  Accordingly, backlog decreased to $203 million at September 30, 2016, from $268 million at June 30, 2016 and $394 million at September 30, 2015, due to project deferrals and delays in award timing resulting from the continued depressed commodity price environment.

Cost of Sales and Services. Our consolidated cost of sales and services decreased $52.8 million, or 28%, in the third quarter of 2016 compared to the third quarter of 2015 as a result of decreased cost of sales and services at our well site services and offshore products segments of $22.6 million, or 34%, and $30.2 million, or 25%, respectively. With cost of sales and services decreasing at a slower rate than our revenues, consolidated gross margin as a percentage of revenues decreased from 27% in the third quarter of 2015 to 24% in the third quarter of 2016 due to lower margins realized in our completion services segment in the third quarter of 2016.

 

Our well site services segment cost of services decreased $22.6 million, or 34%, in the third quarter of 2016 compared to the third quarter of 2015 as a result of a $15.6 million, or 30%, decrease in completion services cost of services and a $7.0 million, or 50%, decrease in drilling services cost of services. These decreases in cost of services, which are strongly correlated to the revenue decreases in these businesses, reflect a reduction in variable costs along with cost reduction measures implemented in response to the material decrease in revenues resulting from continuing industry activity declines. Our well site services segment gross margin as a percentage of revenues decreased from 20% in the third quarter of 2015 to 5% in the third quarter of 2016. Our completion services gross margin as a percentage of revenues decreased from 21% in the third quarter of 2015 to 5% in the third quarter of 2016 primarily due to the decline in revenues. Our drilling services gross margin as a percentage of revenues decreased from 15% in the third quarter of 2015 to 4% in the third quarter of 2016 primarily due to decreased rig utilization and cost absorption.

 

Our offshore products segment cost of sales decreased $30.2 million, or 25%, in the third quarter of 2016 compared to the third quarter of 2015 in correlation with the decrease in revenues. Gross margin as a percentage of revenues remained flat at 31% for both the third quarter of 2016 and 2015 with the impact of reduced volumes offset by a favorable shift in product mix.

 

Selling, General and Administrative Expenses. Selling, general and administrative (SG&A) expenses decreased $2.7 million, or 8%, in the third quarter of 2016 from the prior-year quarter with the impact of cost reduction initiatives and lower sales commissions partially offset by higher employee severance-related charges in the third quarter of 2016.

 

Depreciation and Amortization. Depreciation and amortization expense decreased $1.9 million, or 6%, in the third quarter of 2016 compared to the third quarter of 2015 primarily due to certain assets becoming fully depreciated since September 30, 2015 that, due to the downturn, have not been replaced.

 

 

Other Operating Income. Other operating income was $1.4 million in the third quarter of 2016 as compared to $1.2 million in the third quarter of 2015 primarily due to increases in foreign currency exchange rate gains.

 

Operating (Loss) Income. Consolidated operating (loss) income moved from operating income of $6.6 million in the third quarter of 2015 to an operating loss of $15.6 million in the third quarter of 2016 primarily as a result of decreases in operating income from our offshore products segment of $10.6 million and $11.3 million from our wellsite services segment resulting from decreased revenues caused by continued industry activity declines.

 

Interest Expense and Interest Income. Net interest expense decreased $0.1 million, or 10%, in the third quarter of 2016 compared to the third quarter of 2015 primarily due to decreased amounts outstanding under our revolving credit facility partially offset by unused commitment fees paid to our lenders. Interest expense as a percentage of total debt outstanding increased from 3.9% in the third quarter of 2015 to 5.6% in the third quarter of 2016 due to an increased proportion of interest expense associated with unused commitment fees coupled with lower average borrowings outstanding under our revolving credit facility.

 

Income Tax Expense. The Company’s income tax provision for the three months ended September 30, 2016 was an income tax benefit of $6.0 million, or 35.8% of pretax losses, compared to income tax expense of $4.0 million, or 69.9% of pretax income, for the three months ended September 30, 2015. The higher effective tax rate in the third quarter of 2015 was primarily due to a $3.2 million tax valuation allowance recorded against certain of the Company’s deferred tax assets.

  

Other Comprehensive (Loss) Income. Other comprehensive loss was $5.2 million in the third quarter of 2016 and compares to a loss of $15.3 million in the third quarter of 2015 due to fluctuations in the currency exchange rates compared to the U.S. dollar for certain of the international operations of our reportable segments. For the three months ended September 30, 2016 and 2015, currency translation adjustments recognized as a component of other comprehensive loss were primarily attributable to the United Kingdom and, to a lesser extent, Canada. As of September 30, 2016, the exchange rates of the British pound and the Canadian dollar compared to the U.S. dollar weakened by 3% and 1%, respectively, compared to the exchange rates at June 30, 2016. As of September 30, 2015, the exchange rates of the British pound and the Canadian dollar compared to the U.S. dollar weakened by 4% and 8%, respectively, compared to the exchange rates at June 30, 2015.

 

Nine Months Ended September 30, 2016 Compared to Nine Months Ended September 30, 2015

 

Net loss from continuing operations attributable to the Company for the nine months ended September 30, 2016 was $35.8 million, or $0.71 per diluted share, which included $4.6 million ($3.0 million after-tax, or $0.06 per diluted share) of severance and other downsizing charges. Excluding these charges in the first nine months of 2016, the net loss from continuing operations would have been $32.8 million, or $0.65 per diluted share. These results compare to net income from continuing operations attributable to the Company of $27.3 million, or $0.53 per diluted share, reported for the nine months ended September 30, 2015, which included $4.5 million ($3.3 million after-tax, or $0.06 per diluted share) of severance and other downsizing charges and a higher effective tax rate driven primarily by a $3.5 million ($0.07 per diluted share) valuation allowance recorded against certain of the Company’s deferred tax assets related to tax loss carry forwards and a $2.3 million ($0.05 per diluted share) deferred tax adjustment for certain prior period non-deductible items. Excluding the charges and the effect of the higher effective tax rate in the first nine months of 2015, net income from continuing operations would have been $36.4 million, or $0.71 per diluted share.

 

Revenues. Consolidated revenues decreased $341.0 million, or 39%, in the first nine months of 2016 compared to the first nine months of 2015.

 

Our well site services segment revenues decreased $180.4 million, or 58%, in the first nine months of 2016 compared to the first nine months of 2015 due to decreases in both completion services and drilling services revenues. Our completion services revenues decreased $137.5 million, or 54%, in the first nine months of 2016 compared to the first nine months of 2015, primarily due to a 59% decrease in the number of service tickets completed as a result of continued extreme competitive pressures and depressed activity levels in the U.S. shale basins. Our drilling services revenues decreased $42.9 million, or 75%, in the first nine months of 2016 compared to the first nine months of 2015 primarily as a result of significantly decreased utilization of our drilling rigs from an average of 37% during the first nine months of 2015 to an average of 10% in the first nine months of 2016 primarily due to the continued weak commodity price environment.

 

 

Our offshore products segment revenues decreased $160.6 million, or 29%, in the first nine months of 2016 compared to the first nine months of 2015 primarily as a result of lower contributions across most of the segment’s product lines, driven by a decline in demand for service activities and drilling products, production-related products, and shorter-cycle products (such as valves and elastomer products), as well as a backlog position that has trended lower since mid-2014, partially offset by improved subsea pipeline product revenues. Backlog decreased to $203 million at September 30, 2016, from $340 million at December 31, 2015 and $394 million at September 30, 2015, due to project deferrals and delays in award timing resulting from the continued depressed commodity price environment.

 

Cost of Sales and Services. Our consolidated cost of sales and services decreased $220.0 million, or 35%, in the first nine months of 2016 compared to the first nine months of 2015 as a result of decreased cost of sales and services at our well site services and offshore products segments of $109.8 million, or 47%, and $110.2 million, or 29%, respectively. With cost of sales and services decreasing at a slower rate than our revenues, consolidated gross margin as a percentage of revenues decreased from 28% in the first nine months of 2015 to 24% in the first nine months of 2016 due to significantly lower margins realized in our well site services segment in the first nine months of 2016.

 

Our well site services segment cost of services decreased $109.8 million, or 47%, in the first nine months of 2016 compared to the first nine months of 2015 as a result of a $77.8 million, or 41%, decrease in completion services cost of services and a $32.0 million, or 69%, decrease in drilling services cost of services. These decreases in cost of services, which are strongly correlated to the revenue decreases in these businesses, reflect a reduction in variable costs along with cost reduction measures implemented in response to the material decrease in revenues caused by continuing industry activity declines. Our well site services segment gross margin as a percentage of revenues decreased from 24% in the first nine months of 2015 to 4% in the first nine months of 2016. Our completion services gross margin as a percentage of revenues decreased from 25% in the first nine months of 2015 to 4% in the first nine months of 2016 primarily due to the decline in revenues. Our drilling services gross margin as a percentage of revenues decreased from 18% in the first nine months of 2015 to (3)% in the first nine months of 2016 primarily due to decreased rig utilization and cost absorption.

 

Our offshore products segment cost of sales decreased $110.2 million, or 29%, in the first nine months of 2016 compared to the first nine months of 2015 in correlation with the decrease in revenues. Gross margin as a percentage of revenues remained generally constant (30% in the first nine months of 2016 compared to 31% in the first nine months of 2015).

 

Selling, General and Administrative Expenses. Selling, general and administrative (SG&A) expenses decreased $9.9 million, or 10%, in the first nine months of 2016 compared to the first nine months of 2015 largely due to decreased compensation costs, sales commissions, and travel and entertainment expenses.

 

Depreciation and Amortization. Depreciation and amortization expense decreased $7.1 million, or 7%, in the first nine months of 2016 compared to the first nine months of 2015 primarily due to certain assets becoming fully depreciated since September 30, 2015 that, due to the downturn, have not been replaced.

 

Other Operating Income. Other operating income increased $2.0 million, to $4.1 million, in the first nine months of 2016 compared to the first nine months of 2015 primarily due to increases in foreign currency exchange rate gains.

 

Operating (Loss) Income. Consolidated operating (loss) income moved from operating income of $49.1 million in the first nine months of 2015 to an operating loss of $52.9 million in the first nine months of 2016 primarily as a result of decreases in operating income from our well site services segment of $65.7 million and a $37.0 million decrease in offshore products operating income – both reflecting the impact of significant revenue declines due to lower industry activity.

 

Interest Expense and Interest Income. Net interest expense decreased $0.6 million, or 15%, in the first nine months of 2016 compared to the first nine months of 2015 primarily due to lower amounts outstanding under our revolving credit facility partially offset by unused commitment fees paid to our lenders. Interest expense as a percentage of total debt outstanding increased from 3.5% in the first nine months of 2015 to 5.6% in the first nine months of 2016 due to an increased proportion of interest expense associated with unused commitment fees coupled with lower average borrowings outstanding under our revolving credit facility.

 

 

Income Tax Expense. The Company’s income tax provision for the nine months ended September 30, 2016 was an income tax benefit of $20.5 million, or 36.4% of pretax losses, compared to income tax expense of $18.6 million, or 40.6% of pretax income, for the nine months ended September 30, 2015. The effective tax rate for the nine months ended September 30, 2015 was influenced by a $3.5 million tax valuation allowance recorded against certain of the Company’s deferred tax assets and a $2.3 million deferred tax adjustment for certain prior period non-deductible items.

 

Other Comprehensive Income (Loss). Other comprehensive loss decreased from $20.0 million in the first nine months of 2015 to $12.5 million in the first nine months of 2016 due to fluctuations in the currency exchange rates compared to the U.S. dollar for certain of the international operations of our reportable segments. For the nine months ended September 30, 2016 and 2015, currency translation adjustments recognized as a component of other comprehensive loss were primarily attributable to the United Kingdom and, to a lesser extent, Canada. As of September 30, 2016, the exchange rate of the Canadian dollar compared to the U.S. dollar strengthened by 6% compared to the exchange rate at December 31, 2015, while the exchange rate of the British pound compared to the U.S. dollar weakened by 12% during the same period. As of September 30, 2015, the exchange rates of the British pound and the Canadian dollar compared to the U.S. dollar weakened by 2% and 13%, respectively, compared to the exchange rates at December 31, 2015.

 

Liquidity, Capital Resources and Other Matters

 

Our primary liquidity needs are to fund operating and capital expenditures which, in the past, have included expanding and upgrading our offshore 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 our credit facility, and capital markets transactions.

 

Operating Activities

 

Despite the weak market conditions, cash flows totaling $107.8 million were provided by continuing operations during the first nine months of 2016 compared to $252.8 million provided by continuing operations during the same period of 2015. During the first nine months of 2016, $64.6 million was provided from net working capital reductions, primarily due to decreases in receivables. During the first nine months of 2015, $116.1 million was provided from net working capital reductions, primarily due to decreases in receivables.

 

In June 2016, the Company acquired the Guiberson product line from Cameron International Corporation. The purchase price was allocated to inventory and other intangible assets. 

 

Investing Activities

 

Cash was used in investing activities during the nine months ended September 30, 2016 in the amount of $24.4 million compared to $124.3 million used in investing activities during the nine months ended September 30, 2015. Capital expenditures totaled $23.9 million and $92.3 million during the nine months ended September 30, 2016 and 2015, respectively. Capital expenditures in both periods consisted principally of purchases of completion services equipment, expansion and upgrading of our offshore products segment facilities and various other capital spending initiatives.

 

On January 2, 2015, we acquired all of the equity of MMC. Total transaction consideration was $33.4 million, net of cash acquired, funded from amounts available under the Company’s revolving credit facility.

 

After considering the $23.9 million invested during the first nine months of 2016, we currently expect to invest a total of approximately $35 million to $40 million for capital expenditures during 2016 to upgrade and maintain our offshore products facilities and completion services equipment, and to fund various other capital spending initiatives. Whether planned expenditures will actually be spent in 2016 depends on industry conditions, project approvals and schedules, vendor delivery timing, free flow cash generation, and careful monitoring of our levels of liquidity. We plan to fund these capital expenditures with available cash, internally generated funds, and borrowings under our 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 September 30, 2016, we had cash totaling $52.6 million held by our foreign subsidiaries, primarily in Singapore, the United Kingdom and Canada. Our intent is to utilize at least a portion of these cash balances for future investment outside of the United States. Approximately $29 million of cash held by our international subsidiaries can be repatriated by us without triggering any incremental tax consequences.

 

Financing Activities

 

Net cash of $63.7 million was used in financing activities during the nine months ended September 30, 2016, primarily as a result of repayments of outstanding debt under our revolving credit facility. Net cash of $95.8 million was used in financing activities during the nine months ended September 30, 2015, primarily as a result of repurchases of our common stock totaling $104.6 million.

 

We believe that cash on hand, cash flow from operations, and available borrowings under our 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 the termination of our then existing share repurchase program and authorized a new program providing for the repurchase of up to $150 million of the Company’s common stock, which was scheduled to expire on July 29, 2016. On July 27, 2016, our Board of Directors extended the share repurchase program for one year to July 29, 2017. During the nine months ended September 30, 2016, there were no repurchases of our common stock made under the program. The amount remaining under our current share repurchase authorization as of September 30, 2016 was $136.8 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 under its facility to $750 million contingent upon additional lender commitments prior to its maturity on May 28, 2019. As of September 30, 2016, we had $63.1 million in borrowings outstanding under the Credit Agreement and $27.8 million of outstanding letters of credit, leaving $217.8 million available to be drawn under the revolving credit facility. The total amount available to be drawn under our revolving credit facility was less than the lender commitments as of September 30, 2016, due to the maximum leverage ratio covenant in our revolving credit facility which serves to limit borrowings, and such availability is expected to be further reduced due to reductions in 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. On October 3, 2016, the Company amended the revolving credit facility to, among other things, allow for certain intercompany transactions between or among the Company and its subsidiaries (which may have otherwise been considered investments not permitted under the Credit Agreement) and make certain other technical changes and modifications. 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. 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 nine months of 2016. During the first nine months of 2016, our applicable margin over LIBOR was 1.50%. Interest expense as a percentage of total debt outstanding increased from 3.5% in the first nine months of 2015 to 5.6% in the first nine months of 2016. The increase in the weighted average interest rate was attributable to an increased proportion of interest expense associated with unused commitment fees coupled with lower average borrowings outstanding under our revolving credit facility.

 

 

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 September 30, 2016, we were in compliance with our debt covenants and expect to continue to be in compliance during the remainder of 2016.  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.    

 

Under the Company's 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.

 

Our total debt represented 5.2% of our combined total debt and stockholders’ equity at September 30, 2016 compared to 9.1% at December 31, 2015 and 11.1% at September 30, 2015.

 

Critical Accounting Policies

 

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 2015 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, please see Note 2, “Recent Accounting Pronouncements.”

 

Off-Balance Sheet Arrangements

 

As of September 30, 2016, we had no off-balance sheet arrangements as defined in Item 303(a)(4)(ii) of Regulation S-K.

 

ITEM 3. Quantitative and Qualitative Disclosures about Market Risk

 

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.

 

 

Interest Rate Risk

 

We have a revolving credit facility that is subject to the risk of higher interest charges associated with increases in interest rates. As of September 30, 2016, we had floating-rate obligations totaling $63.1 million drawn under our 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 September 30, 2016 levels, our consolidated interest expense would increase by a total of approximately $0.6 million annually.

 

 

Foreign Currency Exchange Rate Risk

 

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 U.S. (primarily in our offshore 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 nine months ended September 30, 2016, our reported foreign currency exchange gains were $3.4 million and are included in “Other operating income, 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 September 30, 2016 and December 31, 2015, we had outstanding foreign currency forward purchase contracts with notional amounts of $4.4 million and $5.4 million, respectively, related to expected cash flows denominated in Euros. We recorded no other comprehensive losses as a result of these contracts for the nine months ended September 30, 2016 and $0.1 million for the nine months ended September 30, 2015.

 

Our accumulated other comprehensive loss, reported as a component of stockholders’ equity, increased from $50.7 million at December 31, 2015 to $63.2 million at September 30, 2016, as a result of currency exchange rate differences. Our accumulated other comprehensive loss is primarily related to fluctuations in the 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 nine months ended September 30, 2016, currency translation adjustments recognized as a component of other comprehensive loss were primarily attributable to the United Kingdom and Canada. As of September 30, 2016, the exchange rate of the Canadian dollar compared to the U.S. dollar strengthened by 6% compared to the exchange rate at December 31, 2015, while the exchange rate of the British pound compared to the U.S. dollar weakened by 12% during the same period.

 

ITEM 4. Controls and Procedures

 

Evaluation of Disclosure Controls and Procedures

 

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 September 30, 2016 at the reasonable assurance level.

 

Changes in Internal Control Over Financial Reporting

 

During the three months ended September 30, 2016, 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.

 

 

PART II -- OTHER INFORMATION

 

ITEM 1. Legal Proceedings

 

The information with respect to this Item 1 is set forth under Note 14. Commitments and Contingences.

 

ITEM 1A. Risk Factors

 

“Part I, Item 1A. Risk Factors” of our 2015 Form 10-K includes a detailed discussion of our risk factors. The risks described in this Quarterly Report on Form 10-Q and our 2015 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 2015 Form 10-K.

 

ITEM 2. Unregistered Sales of Equity Securities and Use of Proceeds

 

None.

 

 

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

 

Period	Total Number of Shares Purchased	Average Price Paid per Share	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 (1)
July 1 through July 31, 2016	716(2)	$32.84(3)	–	$ 136,827,937
August 1 through August 31, 2016	81(4)	$31.69(5)	–	$ 136,827,937
September 1 through September 30, 2016	–	–	–	$ 136,827,937
Total	797	$32.72	–	$ 136,827,937

 

(1)

On July 29, 2015, the Company’s Board of Directors approved the termination of our then existing share repurchase program and authorized a new program providing for the repurchase of up to $150,000,000 of the Company’s common stock, which was scheduled to expire on July 29, 2016. On July 27, 2016, our Board of Directors extended the share repurchase program for one year to July 29, 2017.

(2)

Includes 716 shares surrendered to us by participants in our 2001 Equity Participation Plan to settle the participants’ personal tax liabilities that resulted from the lapsing of restrictions on shares awarded to the participants under the plan.

(3)

The price paid per share was based on the weighted average closing price of our Company’s common stock on July 2, 2016 and July 28, 2016 which represents the date the restrictions lapsed on such shares.

(4)

Includes 81 shares surrendered to us by participants in our 2001 Equity Participation Plan to settle the participants’ personal tax liabilities that resulted from the lapsing of restrictions on shares awarded to the participants under the plan.

(5)

The price paid per share was based on the closing price of our Company’s common stock on August 11, 2016 which represent the dates the restrictions lapsed on such shares.

 

ITEM 3. Defaults upon Senior Securities

 

None.

 

ITEM 4.  Mine Safety Disclosures.

 

 Not applicable.

 

ITEM 5.  Other Information 

 

None.

 

 

ITEM 6. Exhibits

 

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

 

 

SIGNATURES

 

Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

 

OIL STATES INTERNATIONAL, INC.

 

Date:  October 28, 2016	By	/s/ LLOYD A. HAJDIK
		Lloyd A. Hajdik
		Executive Vice President, Chief Financial Officer and
		Treasurer (Duly Authorized Officer and Principal Financial Officer)

 

 

Exhibit Index

 

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)).
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

---------

*       Filed herewith.

**     Furnished herewith.