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 March 31, 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 incorporation or organization)	(I.R.S. Employer 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)

None

---

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

 

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

YES [ 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 51,360,935 shares of common stock, par value $0.01, outstanding and 10,918,634 shares of treasury stock as of April 26, 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 Income (Loss)	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 – 15
Cautionary Statement Regarding Forward-Looking Statements	16
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	16 – 24
Item 3. Quantitative and Qualitative Disclosures About Market Risk	25
Item 4. Controls and Procedures	25 – 26
Part II -- OTHER INFORMATION
Item 1. Legal Proceedings	26
Item 1A. Risk Factors	26
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	27
Item 6. Exhibits	27
Signature Page	28

 

 

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 INCOME (LOSS)

(In Thousands)

  

 

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

 

 

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

 

CONSOLIDATED BALANCE SHEETS

(In Thousands)

  

 

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

 

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)

 

 

Cautionary Statement Regarding Forward-Looking Statements

 

This quarterly report on Form 10-Q contains certain "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

 

You should read the following discussion and analysis 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 the 2015 Form 10-K.

 

Macroeconomic Environment

 

We are a technology-focused, pure-play 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 oil and natural gas. 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 expected commodity prices, principally related to crude oil and natural gas.

 

 

In the past few years, crude oil prices have been volatile due to global economic uncertainties as well as inadequate regional well site transportation infrastructure. Significant downward crude oil price volatility began early in the fourth quarter of 2014 and has continued into the first quarter of 2016. The material decrease in crude oil prices over this period can primarily be attributed to high levels of global crude oil inventories due to significant production growth in the U.S. shale plays, strengthening of the U.S. dollar throughout 2015 relative to other foreign currencies, and the Organization of Petroleum Exporting Companies (OPEC) increasing its production. OPEC has demonstrated through 2015 and to date in 2016 an unwillingness to cut its production, as it has done in previous years, in an effort to protect market share. These production increases have been offset somewhat by moderate increases in global oil demand. The combination of these factors caused a global supply and demand imbalance for crude oil which, along with concerns regarding the 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 quarter of 2016. The average price of West Texas Intermediate (WTI) crude oil decreased from an average price of $42 per barrel in the fourth quarter of 2015 to an average of $33 per barrel in the first quarter of 2016. These data points compare to an average price of $48 per barrel in the first quarter of 2015. The average price of Intercontinental Exchange Brent (Brent) crude decreased from an average price of $44 per barrel in the fourth quarter of 2015 to an average of $34 per barrel in the first quarter of 2016. These data points compare to an average price of $54 per barrel in the first quarter of 2015. As of April 26, 2016, WTI crude traded at approximately $43 per barrel while Brent crude traded at approximately $44 per barrel. The magnitude of the supply/demand imbalance has created a market concern that crude oil prices could decline further or remain at their currently low level for the foreseeable future, with the current twelve-month forward strip price for WTI and Brent crude each averaging $48 per barrel. The current and expected price for WTI crude 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. The price for Brent crude will 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 prices, there remains a high degree of risk that prices could remain at depressed levels or deteriorate further due to high levels of domestic crude oil production (albeit U.S. production has been declining), slowing growth rates in various global regions and/or the potential for ongoing supply/demand imbalances. Conversely, if the global supply of 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 U.S. and countries such as China and India, a recovery in WTI and Brent crude 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 further decline.

 

Prices for natural gas in the U.S. averaged $1.99 per mmBtu in the first quarter of 2016 compared to $2.12 per mmBtu in the fourth quarter of 2015 and $2.90 per mmBtu in the first quarter of 2015. Natural gas prices declined during the first quarter of 2016 largely due to a continued oversupply of natural gas inventories and a warm 2015-2016 winter season. Natural gas prices traded at approximately $2.06 per mmBtu as of April 26, 2016. Strong production and a milder winter this year compared to last year resulted in significant increases in natural gas inventories in the U.S. during the first quarter of 2016, from 12% below the 5-year average as of the end of the first quarter of 2015 to 52% above the 5-year average as of the end of the first quarter of 2016. Customer spending in the natural gas shale plays has been limited due to associated 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 production growth outpacing demand growth in the U.S., natural gas prices continue to be weak and are expected to remain below levels considered economical for new investments in numerous natural gas fields, with the current twelve-month forward strip price for natural gas averaging $2.69 per mmBtu. If natural gas production growth continues to surpass demand growth in the U.S. and/or 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 and result in fewer rigs drilling for natural gas.

  

 

Recent WTI crude, 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)
3/31/2016			$	33.35			$	33.84			$	1.99
12/31/2015				41.94				43.56				2.12
9/30/2015				46.49				50.44				2.76
6/30/2015				57.85				61.65				2.75
3/31/2015				48.49				53.98				2.90
12/31/2014(2)				73.21				76.43				3.78
9/30/2014				97.87				101.90				3.96
6/30/2014				103.35				109.69				4.61
3/31/2014				98.68				108.14				5.18
12/31/2013				97.50				109.23				3.85

 

(1)

Source: U.S. Energy Information Administration (EIA). As of April 26, 2016, WTI crude, Brent crude and natural gas traded at approximately $43 per barrel, $44 per barrel and $2.06 per mmBtu, respectively.

 

(2)

As of December 31, 2014, the price of WTI and Brent crude oil had fallen to $53.45 per barrel and $55.27 per barrel, respectively.

 

Overview

 

Demand for the products and services of our offshore products segment is tied primarily to the long-term outlook for commodity prices. Demand for our well site services segment responds to shorter-term movements in 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 the general global economic environment 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 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 continued declines in crude oil prices that have 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 deep water projects, 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 have declined in 2015 and 2016.    

 

Bidding and quoting activity along with receipts of purchase orders from customers for our offshore products segment continued during the first quarter of 2016, albeit at a slower pace. Accordingly, backlog in our offshore products segment decreased to $306 million at March 31, 2016 from $340 million at December 31, 2015 due to project deferrals and delays in award timing resulting from the continued depressed commodity price environment. Backlog totaled $474 million at March 31, 2015.

 

Our well site services business segment is primarily affected by drilling and completion activity in the U.S., 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.

  

 

In the past few 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 the most current 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 in recent months due to much lower crude oil prices, totaling 343 rigs as of April 22, 2016. The April 22, 2016 oil rig count comprised approximately 80% of total U.S. drilling activity. The remaining 20% of drilling activity is largely natural gas related. The U.S. natural gas-related working rig count has declined from more than 810 rigs at the beginning of 2012 to 88 rigs as of April 22, 2016, a more than 28 year low. Unless commodity prices improve, we expect that the rig count and demand from our customers for our well site services will remain low during 2016.

 

In our well site services business 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 laterals 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 Rocky Mountain area in the U.S., 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 for
		As Of				Three Months Ended
		April 22,				March 31,
		2016				2016				2015
U.S. Land – Oil			323				420				1,052
U.S. Land – Natural gas and other			82				104				279
U.S. Offshore			26				27				49
Total U.S.			431				551				1,380
Canada			40				173				309
Total North America			471				724				1,689

 

The average North American rig count for the three months ended March 31, 2016 decreased 965 rigs, or 57%, compared to the three months ended March 31, 2015 in response to much lower crude oil prices from the levels experienced in 2014 and the first quarter of 2015.

 

Exacerbating the steep declines in drilling activity, many of our exploration and production customers have been and are continuing to defer well completions. 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 completion activity, DUCs continue to 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, have adversely affected our results of operations, cash flows and financial position as of and for the quarter ended March 31, 2016. If the current pricing environment for oil and natural gas continues, our customers could 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 during the remainder of 2016. 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, many customers have experienced a significant reduction in liquidity and access to the capital and debt markets. There have already been several exploration and production companies who have declared bankruptcy and others who are 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, may 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. We currently expect to spend a total of approximately $45 million to $50 million for capital expenditures during 2016, including approximately $19 million of carry-over from 2015, to upgrade and maintain our offshore products facilities and completion services equipment and to fund various other capital spending projects. Whether planned expenditures will actually be spent in 2016 depends on industry conditions, project approvals and schedules, vendor delivery timing, free cash flow generation, and careful monitoring of our levels of liquidity. 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 an 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 months ended March 31, 2016 and 2015 is summarized below (in millions, except % amounts):

 

		THREE MONTHS ENDED
		March 31,
										Variance
										2016 vs. 2015
		2016				2015				$				%
Revenues
Well site services -
Completion services		$	41.0			$	118.1			$	(77.1	)			(65	)%
Drilling services			2.8				23.7				(20.9	)			(88	)%
Total well site services			43.8				141.8				(98.0	)			(69	)%
Offshore products			125.9				195.6				(69.7	)			(36	)%
Total		$	169.7			$	337.4			$	(167.7	)			(50	)%
Product costs; service and other costs (“Cost of sales and service”)
Well site services -
Completion services		$	40.4			$	80.7			$	(40.3	)			(50	)%
Drilling services			3.9				18.9				(15.0	)			(79	)%
Total well site services			44.3				99.6				(55.3	)			(56	)%
Offshore products			84.5				138.1				(53.6	)			(39	)%
Total		$	128.8			$	237.7			$	(108.9	)			(46	)%
Gross margin
Well site services -
Completion services		$	0.6			$	37.4			$	(36.8	)			(98	)%
Drilling services			(1.1	)			4.8				(5.9	)			(123	)%
Total well site services			(0.5	)			42.2				(42.7	)			(101	)%
Offshore products			41.4				57.5				(16.1	)			(28	)%
Total		$	40.9			$	99.7			$	(58.8	)			(59	)%
Gross margin as a percentage of revenues
Well site services -
Completion services			1	%			32	%
Drilling services			(39	)%			20	%
Total well site services			(1	)%			30	%
Offshore products			33	%			29	%
Total			24	%			30	%

 

 

THREE MONTHS ENDED MARCH 31, 2016 COMPARED TO THREE MONTHS ENDED MARCH 31, 2015

 

We reported a net loss from continuing operations attributable to the Company for the quarter ended March 31, 2016 of $13.2 million, or $0.26 per diluted share, which included $1.6 million of severance and other downsizing charges. Excluding these first quarter of 2016 charges, the net loss from continuing operations would have been $12.2 million, or $0.24 per diluted share. These results compare to net income from continuing operations attributable to the Company of $19.4 million, or $0.38 per diluted share, reported for the quarter ended March 31, 2015, including $2.1 million of severance and other downsizing initiatives, and a higher effective tax rate driven primarily by a $2.3 million deferred tax adjustment for certain prior period non-deductible items related to stock-based compensation. Excluding the first quarter 2015 significant charges and higher effective tax rate, net income from continuing operations would have been $23.1 million, or $0.45 per diluted share.

 

Revenues. Consolidated revenues decreased $167.7 million, or 50%, in the first quarter of 2016 compared to the first quarter of 2015.

 

Our well site services segment revenues decreased $98.0 million, or 69%, in the first quarter of 2016 compared to the first quarter of 2015 due to decreases in both completion services and drilling services revenues. Our completion services revenues decreased $77.1 million, or 65%, in the first quarter of 2016 compared to the first quarter of 2015, primarily due to a 66% decrease in the number of service tickets completed as a result of continued depressed activity levels in the U.S. shale basins. Our drilling services revenues decreased $20.9 million, or 88%, in the first quarter of 2016 compared to the first quarter of 2015 primarily as a result of significantly decreased utilization of our drilling rigs from an average of 44% during the first quarter of 2015 to an average of 6% in the first quarter of 2016 primarily due to the weak commodity price environment.

 

Our offshore products segment revenues decreased $69.7 million, or 36%, in the first quarter of 2016 compared to the first quarter of 2015. This decrease was primarily the result of lower contributions across most of the segment’s product lines, especially drilling products and service activities, weaker demand for shorter-cycle products (such as valves and elastomer products) and a backlog position that has trended lower since mid-2014, partially offset by improved subsea product revenues.

 

Cost of Sales and Service. Our consolidated cost of sales and services decreased $108.9 million, or 46%, in the first quarter of 2016 compared to the first quarter of 2015 as a result of decreased cost of sales and services at our well site services and offshore products segments of $55.3 million, or 56%, and $53.6 million, or 39%, respectively. With cost of sales and service decreasing at a slower rate than our revenues, consolidated gross margin as a percentage of revenues decreased from 30% in the first quarter of 2015 to 24% in the first quarter of 2016 primarily due to lower margins realized in our well site services segment in the first quarter of 2016.

 

Our well site services segment cost of services decreased $55.3 million, or 56%, in the first quarter of 2016 compared to the first quarter of 2015 as a result of a $40.3 million, or 50%, decrease in completion services cost of services and a $15.0 million, or 79%, decrease in drilling services cost of services. These decreases in cost of sales, which are strongly correlated to the revenue decreases in these businesses, reflect 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 30% in the first quarter of 2015 to (1)% in the first quarter of 2016. Our completion services gross margin as a percentage of revenues decreased from 32% in the first quarter of 2015 to 1% in the first quarter of 2016 primarily due to the decline in revenues. Our drilling services gross margin as a percentage of revenues decreased from 20% in the first quarter of 2015 to (39)% in the first quarter of 2016 primarily due to decreased rig utilization and cost absorption.

 

Our offshore products segment cost of sales decreased $53.6 million, or 39%, in the first quarter of 2016 compared to the first quarter of 2015 in correlation with the decrease in revenues. Gross margin as a percentage of revenues increased from 29% in the first quarter of 2015 to 33% in the first quarter of 2016 due to strong project execution on several jobs nearing completion during the first quarter of 2016 combined with a lower overall cost structure.

 

 

Selling, General and Administrative Expenses. Selling, general and administrative (SG&A) expense decreased $5.6 million, or 16%, in the first quarter of 2016 compared to the first quarter of 2015 largely due to decreased compensation including wages and benefits, short-term incentive compensation and stock compensation expense coupled with a decrease in travel and entertainment expenses, commissions and professional fees. These decreases in SG&A expense were partially offset by an increase in our allowance for bad debts reserve.

 

Depreciation and Amortization. Depreciation and amortization expense decreased $2.2 million, or 7%, in the first quarter of 2016 compared to the first quarter of 2015 primarily due to certain assets becoming fully depreciated since March 31, 2015 that, due to the downturn, have not been replaced.

 

Other Operating Expense (Income). Other operating expense (income) moved from other operating income of $2.3 million in the first quarter of 2015 to other operating expense of $0.6 million in the first quarter of 2016 primarily due to increases in foreign currency exchange losses.

 

Operating (Loss) Income. Consolidated operating (loss) income moved from operating income of $33.8 million in the first quarter of 2015 to an operating loss of $20.1 million in the first quarter of 2016 primarily as a result of decreases in operating income from our well site services segment of $42.4 million resulting from decreased revenues caused by industry activity declines, and a $13.2 million decrease in offshore products operating income.

 

Interest Expense and Interest Income. Net interest expense decreased $0.2 million, or 14%, in the first quarter of 2016 compared to the first quarter of 2015 primarily due to decreased amounts outstanding under our bank credit facility partially offset by unused commitment fees paid to our lenders. The weighted average interest rate on the Company’s total outstanding debt increased from 3.3% in the first quarter of 2015 to 5.0% in the first quarter of 2016 due to an increased proportion of interest expense associated with unused commitment fees coupled with lower average outstanding borrowings under our revolving credit facility.

  

Income Tax Expense. The Company’s income tax provision for the three months ended March 31, 2016 was a total tax benefit of $8.0 million, or 37.7% of pretax losses, compared to income tax expense of $13.3 million, or 40.6% of pretax income, for the three months ended March 31, 2015. The effective tax rate for the three months ended March 31, 2015 included a $2.3 million deferred tax adjustment in the first quarter of 2015 for certain prior period non-deductible items related to stock-based compensation.

 

Other Comprehensive Income (Loss). Other comprehensive income (loss) increased from a loss of $14.5 million in the first quarter of 2015 to income of $1.6 million in the first quarter of 2016 primarily as a result of fluctuations in the foreign currency exchange rates compared to the U.S. dollar for the foreign operations of our reportable segments (primarily in the United Kingdom, Canada, Brazil, and Argentina). The exchange rates of the Canadian dollar and the Brazilian real compared to the U.S. dollar strengthened by 6% and 8%, respectively, in the first quarter of 2016 compared to the exchange rates at December 31, 2015, while the exchange rates of the British pound and the Argentine peso compared to the U.S. dollar weakened by 3% and 11%, respectively, during the same period.

 

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 facilities and capital markets transactions.

 

Operating Activities

 

Despite the weak market conditions, cash totaling $56.8 million was provided by continuing operations during the first quarter of 2016 compared to $114.4 million provided by continuing operations during the first quarter of 2015. During the first quarter of 2016, $44.9 million was provided from net working capital reductions, primarily due to decreases in receivables. During the first quarter of 2015, $51.8 million was provided from net working capital reductions, primarily due to decreases in receivables.

 

 

Investing Activities

 

Cash was used in investing activities during the three months ended March 31, 2016 in the amount of $9.7 million compared to $71.6 million used in investing activities during the three months ended March 31, 2015. Capital expenditures for continuing operations totaled $10.3 million and $38.3 million during the three months ended March 31, 2016 and 2015, respectively. Capital expenditures in both years 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 credit facility.

 

We currently expect to spend a total of approximately $45 million to $50 million for capital expenditures during 2016 including approximately $19 million of carry-over from 2015, 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 March 31, 2016, we had cash totaling $41.9 million held by 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 the United States. Approximately $37 million of cash held by our foreign subsidiaries can be repatriated without triggering any incremental tax consequences.

 

Financing Activities

 

Net cash of $40.4 million was used in financing activities during the three months ended March 31, 2016, primarily as a result of repayments of outstanding debt under our revolving credit facility. Net cash of $23.6 million was used in financing activities during the three months ended March 31, 2015, primarily as a result of repurchases of our common stock totaling $77.4 million partially offset by borrowings under our revolving credit facility.

 

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 the issuance of additional equity securities could result in significant dilution to stockholders.

 

Share Repurchase Program. On September 6, 2013, the Company announced an increase in its Board-authorized Company share repurchase program from $200 million to $500 million providing for the repurchase of the Company’s common stock, par value $.01 per share. 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, par value $.01 per share. The new program is set to expire on July 29, 2016. During the first quarter of 2016, there were no repurchases of our common stock made under our current program. As of March 31, 2016, a total of $456.0 million of our stock (6,902,748 shares, or approximately 13% of the outstanding shares of our common stock at the initiation of our initial share repurchase authorization in August 2012) had been repurchased under these programs. The amount remaining available under our current share repurchase authorization as of March 31, 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 Facilities. The Company has a $600 million senior secured revolving credit facility (the revolving credit facility) with an option to increase the maximum borrowings under the new facility to $750 million contingent upon additional lender commitments prior to its maturity on May 28, 2019. The credit facility is governed by a Credit Agreement dated as of May 28, 2014 (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 (as defined in the Credit Agreement). During the first quarter of 2016, our applicable margin over LIBOR was 1.50%. The weighted average interest rate on the Company’s total outstanding debt increased from 3.3% in the first quarter of 2015 to 5.0% in the first quarter 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 outstanding borrowings under our revolving credit facility. 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 quarter of 2016.

 

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 March 31, 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.    

 

As of March 31, 2016, we had $86.1 million in borrowings outstanding under the Credit Agreement and $38.4 million of outstanding letters of credit. As of March 31, 2016, $364.6 million was available to be drawn under the credit facility. The total amount available to be drawn under our revolving credit facility was less than the lender commitments as of March 31, 2016, due to the maximum leverage ratio covenant in our credit facility which serves to limit borrowings, and such availability is expected to be further reduced as our trailing twelve months EBITDA moves lower into 2016 given that, in accordance with the Credit Agreement, total debt cannot exceed 3.25 times our trailing twelve months EBITDA.

 

Our total debt represented 6.9% of our combined total debt and stockholders’ equity at March 31, 2016 compared to 9.3% at December 31, 2015 and 14.0% at March 31, 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 March 31, 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 credit facilities that are subject to the risk of higher interest charges associated with increases in interest rates. As of March 31, 2016, we had floating-rate obligations totaling $86.1 million drawn under our 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 March 31, 2016 levels, our consolidated interest expense would increase by a total of approximately $0.9 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 exchange rate risks in areas outside 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 three months ended March 31, 2016, our reported foreign exchange losses were $0.8 million and are included in “Other operating expense (income)” in the Consolidated Statements of Operations. In order to reduce our exposure to fluctuations in currency exchange rates, we may enter into foreign exchange agreements with financial institutions. As of March 31, 2016 and December 31, 2015, we had outstanding foreign currency forward purchase contracts with notional amounts of $4.6 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 three months ended March 31, 2016 and less than $0.1 million for the three months ended March 31, 2015.

 

Our accumulated other comprehensive loss, reported as a component of stockholders’ equity, decreased from $50.7 million at December 31, 2015 to $49.1 million at March 31, 2016, primarily as a result of foreign currency exchange rate differences. Our accumulated other comprehensive loss is primarily related to fluctuations in the foreign currency exchange rates compared to the U.S. dollar which are used to remeasure the foreign operations of our reportable segments (primarily in the United Kingdom, Canada, Brazil, and Argentina). The exchange rates of the Canadian dollar and the Brazilian real compared to the U.S. dollar strengthened by 6% and 8%, respectively, in the first quarter of 2016 compared to the exchange rates at December 31, 2015, while the exchange rates of the British pound and the Argentine peso compared to the U.S. dollar weakened by 3% and 11%, respectively, 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 March 31, 2016 at the reasonable assurance level.

 

 

Changes in Internal Control Over Financial Reporting

 

In January 2016, we completed the implementation of a new financial and inventory accounting system in our completion services business. We believe the new software will enhance our internal controls over financial reporting, and we believe that we have taken the necessary steps to maintain appropriate internal control over financial reporting during this period of system change. We plan to monitor controls through and around the system to provide reasonable assurance that controls are effective.

 

During the three months ended March 31, 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), other than described above, 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

 

In the ordinary course of conducting our business, we become involved in litigation and other claims from private party actions, as well as judicial and administrative proceedings involving governmental authorities at the federal, state and local levels. During 2014 and early 2015, a number of lawsuits were filed by current and former employees, in Federal Court against the Company and or one of its subsidiaries, alleging violations of the Fair Labor Standards Act (“FLSA”). The plaintiffs seek damages and penalties for the Company’s alleged failure to: properly classify its field service employees as “non-exempt” under the FLSA; and pay them on an hourly basis (including overtime). The plaintiffs are seeking recovery on their own behalf as well as on behalf of a class of similarly situated employees. Settlement of the class action against the Company was approved and a judgment was entered November 19, 2015. The Company has settled the vast majority of these claims and is evaluating potential settlements for the remaining individual plaintiffs’ claims which are not expected to be significant.

 

We are a party to various pending or threatened claims, lawsuits and administrative proceedings seeking damages or other remedies concerning our commercial operations, products, employees and other matters, including occasional claims by individuals alleging exposure to hazardous materials as a result of our products or operations. Some of these claims relate to matters occurring prior to our acquisition of businesses, and some relate to businesses we have sold. In certain cases, we are entitled to indemnification from the sellers of businesses, and in other cases, we have indemnified the buyers of businesses from us. Although we can give no assurance about the outcome of pending legal and administrative proceedings and the effect such outcomes may have on us, we believe that any ultimate liability resulting from the outcome of such proceedings, to the extent not otherwise provided for or covered by indemnity or insurance, will not have a material adverse effect on our consolidated financial position, results of operations or liquidity.

 

ITEM 1A. Risk Factors

 

“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)
January 1, 2016 – January 31, 2016	488(2)	$27.25(3)	--	$ 136,827,937
February 1, 2016 – February 29, 2016	158,236(4)	$24.42(5)	--	$ 136,827,937
March 1, 2016 - March 31, 2016	182(6)	$30.47(7)	--	$ 136,827,937
Total	158,906	$24.44	--	$ 136,827,937

 

(1)

On August 23, 2012, we announced a share repurchase program of up to $200,000,000 to replace the prior share repurchase authorization. On September 6, 2013, we announced an increase in the program from $200,000,000 to $500,000,000. On July 29, 2015, the Company’s Board of Directors approved the termination of our 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. The new program is set to expire on July 29, 2016.

(2)

Includes 488 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 January 1, 2016 which represents the date the restrictions lapsed on such shares.

(4)

Includes 158,236 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 February 16, 2016, February 18, 2016 and February 19, 2016 which represent the dates the restrictions lapsed on such shares.

(6)

Includes 182 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.

(7)

The price paid per share was based on the closing price of our Company’s common stock on March 30, 2016 which represent the dates the restrictions lapsed on such shares.

 

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, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

 

OIL STATES INTERNATIONAL, INC.

 

	Date:	April 28, 2016		By	/s/ LLOYD A. HAJDIK
					Lloyd A. Hajdik
					Senior Vice President, Chief Financial Officer and Treasurer (Duly Authorized Officer and Principal Financial Officer)
	Date:	April 28, 2016		By	/s/ SARAH A. MUNSON
					Sarah A. Munson
					Vice President, Controller and Chief Accounting Officer (Duly Authorized Officer and Chief Accounting 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.
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.
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.
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.
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.