Parker Drilling (PKDC) 10-Q 2016 Q3 Quarterly report

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 1-7573

PARKER DRILLING COMPANY

(Exact name of registrant as specified in its charter)

Delaware	73-0618660
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
5 Greenway Plaza, Suite 100, Houston, Texas	77046
(Address of principal executive offices)	(Zip code)

(281) 406-2000

(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	¨	Accelerated filer	x
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

As of October 27, 2016 there were 125,055,485 common shares outstanding.    

TABLE OF CONTENTS

	Page
Part I. Financial Information
Item 1. Financial Statements	3
Consolidated Condensed Balance Sheets as at September 30, 2016 (Unaudited) and December 31, 2015	3
Consolidated Condensed Statements of Operations (Unaudited) for the Three and Nine Months Ended September 30, 2016 and 2015	4
Consolidated Condensed Statements of Comprehensive Income (Loss) (Unaudited) for the Three and Nine Months Ended September 30, 2016 and 2015	5
Consolidated Condensed Statements of Cash Flows (Unaudited) for the Nine Months Ended September 30, 2016 and 2015	6
Notes to the Unaudited Consolidated Condensed Financial Statements	7
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	30
Item 3. Quantitative and Qualitative Disclosures about Market Risk	46
Item 4. Controls and Procedures	46
Part II. Other Information
Item 1. Legal Proceedings	47
Item 1A. Risk Factors	47
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	47
Item 3. Defaults Upon Senior Securities	47
Item 4. Mine Safety Disclosures	47
Item 5. Other Information	47
Item 6. Exhibits	48
Signatures	49

2

PART I.FINANCIAL INFORMATION

Item 1. Financial Statements

PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATED CONDENSED BALANCE SHEETS

(Dollars in Thousands)

	September 30, 2016			December 31, 2015
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	103,613		$	134,294
Accounts and Notes Receivable, net of allowance for bad debts of $7,388 at September 30, 2016 and $8,694 at December 31, 2015.	130,616			175,105
Rig materials and supplies	32,681			34,937
Other current assets	22,514			22,405
Total current assets	289,424			366,741
Property, plant and equipment, net of accumulated depreciation of $1,374,409 at September 30, 2016 and $1,302,380 at December 31, 2015.	718,254			805,841
Goodwill	6,708			6,708
Intangible assets, net	10,660			13,377
Deferred income taxes	87,653			139,282
Other noncurrent assets	37,183			34,753
Total assets	$	1,149,882		$	1,366,702
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities	86,107			129,703
Accrued income taxes	7,186			6,418
Total current liabilities	93,293			136,121
Long-term debt, net of unamortized debt issuance costs of $9,065 at September 30, 2016 and $10,202 at December 31, 2015.	575,935			574,798
Other long-term liabilities	16,161			18,617
Deferred tax liability	78,893			68,654
Commitments and contingencies (Note 11)
Stockholders’ equity:
Common stock	20,829			20,518
Capital in excess of par value	671,977			669,120
Accumulated deficit	(301,123		)	(119,238		)
Accumulated other comprehensive income (loss)	(6,083		)	(1,888		)
Total stockholders’ equity	385,600			568,512
Total liabilities and stockholders’ equity	$	1,149,882		$	1,366,702

See accompanying notes to the unaudited consolidated condensed financial statements.

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PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENTS OF OPERATIONS

(Dollars in Thousands, Except Per Share Data)

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
Revenues	$	97,189		$	173,418		$	332,979		$	563,435
Expenses:
Operating expenses	84,680			128,963			281,992			411,802
Depreciation and amortization	34,474			39,584			106,605			118,474
	119,154			168,547			388,597			530,276
Total operating gross margin (loss)	(21,965		)	4,871			(55,618		)	33,159
General and administration expense	(7,424		)	(8,895		)	(25,200		)	(29,243		)
Provision for reduction in carrying value of certain assets	—			(906		)	—			(3,222		)
Gain (loss) on disposition of assets, net	(187		)	383			(249		)	2,686
Total operating income (loss)	(29,576		)	(4,547		)	(81,067		)	3,380
Other income (expense):
Interest expense	(11,015		)	(11,293		)	(34,764		)	(33,767		)
Interest income	9			7			48			209
Other	(351		)	(719		)	1,776			(3,628		)
Total other income (expense)	(11,357		)	(12,005		)	(32,940		)	(37,186		)
Income (loss) before income taxes	(40,933		)	(16,552		)	(114,007		)	(33,806		)
Income tax expense (benefit)	5,295			31,930			67,878			24,832
Net income (loss)	(46,228		)	(48,482		)	(181,885		)	(58,638		)
Less: Net income (loss) attributable to noncontrolling interest	—			138			—			789
Net income (loss) attributable to controlling interest	$	(46,228	)	$	(48,620	)	$	(181,885	)	$	(59,427	)
Basic income (loss) per share	$	(0.37	)	$	(0.40	)	$	(1.47	)	$	(0.49	)
Diluted income (loss) per share	$	(0.37	)	$	(0.40	)	$	(1.47	)	$	(0.49	)
Number of common shares used in computing earnings per share:
Basic	124,486,848			122,933,518			123,894,980			122,430,957
Diluted	124,486,848			122,933,518			123,894,980			122,430,957

See accompanying notes to the unaudited consolidated condensed financial statements.

4

PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Dollars in Thousands)

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
Comprehensive income (loss):
Net income (loss)	$	(46,228	)	$	(48,482	)	$	(181,885	)	$	(58,638	)
Other comprehensive income (loss), net of tax:
Currency translation difference on related borrowings	116			(1,285		)	311			(2,308		)
Currency translation difference on foreign currency net investments	(740		)	588			(4,506		)	1,462
Total other comprehensive income (loss), net of tax:	(624		)	(697		)	(4,195		)	(846		)
Comprehensive income (loss)	(46,852		)	(49,179		)	(186,080		)	(59,484		)
Comprehensive income (loss) attributable to noncontrolling interest	—			(82		)	—			(571		)
Comprehensive income (loss) attributable to controlling interest	$	(46,852	)	$	(49,261	)	$	(186,080	)	$	(60,055	)

See accompanying notes to the unaudited consolidated condensed financial statements.

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PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)

(Unaudited)

	Nine Months Ended September 30,
	2016			2015
Cash flows from operating activities:
Net income (loss)	$	(181,885	)	$	(58,638	)
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization	106,605			118,474
Accretion of contingent consideration	419			547
(Gain) loss on debt modification	1,088			—
Provision for reduction in carrying value of certain assets	—			3,222
(Gain) loss on disposition of assets	249			(2,686		)
Deferred income tax expense (benefit)	61,199			10,259
Expenses not requiring cash	(4,031		)	8,029
Change in assets and liabilities:
Accounts and notes receivable	44,799			51,254
Other assets	3,282			1,486
Accounts payable and accrued liabilities	(30,590		)	(15,790		)
Accrued income taxes	(1,992		)	(7,305		)
Net cash provided by (used in) operating activities	(857		)	108,852
Cash flows from investing activities:
Capital expenditures	(20,994		)	(72,469		)
Proceeds from the sale of assets	2,296			731
Proceeds from insurance settlements	—			2,500
Acquisition, net of cash acquired	—			(10,431		)
Net cash provided by (used in) investing activities	(18,698		)	(79,669		)
Cash flows from financing activities:
Repayments of long-term debt	—			(30,000		)
Payments of debt issuance costs	—			(1,996		)
Payment for noncontrolling interest	(3,375		)	—
Payments of contingent consideration	(6,000		)	—
Excess tax (expense) from stock based compensation	(1,751		)	(992		)
Net cash provided by (used in) financing activities	(11,126		)	(32,988		)
Net increase (decrease) in cash and cash equivalents	(30,681		)	(3,805		)
Cash and cash equivalents, beginning of year	134,294			108,456
Cash and cash equivalents, end of period	$	103,613		$	104,651
Supplemental cash flow information:
Interest paid	$	41,175		$	41,393
Income taxes paid	$	12,142		$	21,627

See accompanying notes to the unaudited consolidated condensed financial statements.

6

PARKER DRILLING COMPANY AND SUBSIDIARIES

NOTES TO THE UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

Note 1 - General

The Consolidated Condensed Financial Statements as of September 30, 2016 and for the three and nine months ended September 30, 2016 and 2015 are unaudited. In the opinion of Parker Drilling Company (Parker Drilling or the Company), these financial statements include all adjustments, which, unless otherwise disclosed, are of a normal recurring nature, necessary for a fair presentation of the financial position, results of operations, comprehensive income, and cash flows for the periods presented. The results for interim periods are not necessarily indicative of results for the entire year. The financial statements presented herein should be read in connection with the financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2015.

Nature of Operations — Our business is comprised of two business lines: (1) Drilling Services and (2) Rental Tools Services. We report our Drilling Services business as two reportable segments: (1) U.S. (Lower 48) Drilling and (2) International & Alaska Drilling. Effective July 1, 2016, we report our Rental Tools Services business as two reportable segments: (1) U.S. Rental Tools and (2) International Rental Tools. We have revised our business segment reporting to reflect our current management approach and recast prior periods to conform to the current business segment presentation.

In our Drilling Services business, we drill oil and gas wells for customers in both the United States (U.S.) and international markets. We provide this service with both Company-owned rigs and customer-owned rigs. We refer to the provision of drilling services with customer-owned rigs as our operations and maintenance (O&M) service in which operators own their own drilling rigs but choose Parker Drilling to operate and maintain the rigs for them. The nature and scope of activities involved in drilling an oil and gas well are similar whether the well is drilled with a Company-owned rig (as part of a traditional drilling contract) or a customer-owned rig (as part of an O&M contract). In addition, we provide project related services, such as engineering, procurement, project management and commissioning of customer owned drilling facility projects. We have extensive experience and expertise in drilling geologically difficult wells and in managing the logistical and technological challenges of operating in remote, harsh and ecologically sensitive areas.

    Our U.S. (Lower 48) Drilling segment provides drilling services with our Gulf of Mexico (GOM) barge drilling fleet, and markets our U.S. (Lower 48) based O&M services. Our GOM barge drilling fleet operates barge rigs that drill for oil and natural gas in shallow waters in and along the inland waterways and coasts of Louisiana, Alabama and Texas. The majority of these wells are drilled in shallow water depths ranging from 6 to 12 feet. Our International & Alaska Drilling segment provides drilling services, with Company-owned rigs as well as through O&M contracts, and project related services. We strive to deploy our fleet of Company-owned rigs in markets where we expect to have opportunities to keep the rigs consistently utilized and build a sufficient presence to achieve efficient operating scale.    

In our Rental Tools Services business, we provide premium rental equipment and services to exploration and production (E&P) companies, drilling contractors and service companies on land and offshore in the U.S. and select international markets. Tools we provide include standard and heavy-weight drill pipe, all of which are available with standard or high-torque connections, tubing, pressure control equipment, including blow-out preventers (BOPs), drill collars and more. We also provide well construction services, which include tubular running services and downhole tools, and well intervention services, which include whipstock, fishing products and related services, as well as inspection and machine shop support. Rental tools are used during well drilling programs and are requested by the customer when they are needed, requiring us to keep a broad inventory of rental tools in stock. Rental tools are usually rented on a daily or monthly basis.

Consolidation — The consolidated condensed financial statements include the accounts of the Company and subsidiaries over which we exercise control or in which we have a controlling financial interest, including entities, if any, in which the Company is allocated a majority of the entity’s losses or returns, regardless of ownership percentage. If a subsidiary of Parker Drilling has a 50 percent interest in an entity but Parker Drilling’s interest in the subsidiary or the entity does not meet the consolidation criteria, then that interest is accounted for under the equity method.

Noncontrolling Interest— We apply accounting standards related to noncontrolling interests for ownership interests in our subsidiaries held by parties other than Parker Drilling. We report noncontrolling interest as equity on the consolidated balance sheets and report net income (loss) attributable to controlling interest and to noncontrolling interest separately on the consolidated condensed statements of operations. During the fourth quarter of 2015, we purchased the remaining noncontrolling interest of ITS Arabia Limited for $6.75 million, of which $3.4 million was paid in the 2015 fourth quarter. The final payment of the purchase price was made during the second quarter of 2016. At the time of purchase, the carrying value of the noncontrolling interest was $3.0 million.

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Reclassifications — Certain reclassifications have been made to prior period amounts to conform to the current period presentation. These reclassifications did not materially affect our consolidated financial results.

Revenue Recognition — Drilling revenues and expenses, comprised of daywork drilling contracts, call-outs against master service agreements and engineering and related project services contracts, are recognized as services are performed and collection is reasonably assured. For certain contracts, we receive payments contractually designated for the mobilization of rigs and other drilling equipment. Mobilization payments received, and direct costs incurred for the mobilization, are deferred and recognized over the primary term of the related drilling contract; however, costs incurred to relocate rigs and other drilling equipment to areas in which a contract has not been secured are expensed as incurred. For contracts that are terminated prior to the specified term, early termination payments received by us are recognized as revenues when all contractual requirements are met. Revenues from rental activities are recognized ratably over the rental term, which is generally less than six months. Our project related services contracts include engineering, consulting, and project management scopes of work and revenue is typically recognized on a time and materials basis.

Reimbursable Revenues — The Company recognizes reimbursements received for out-of-pocket expenses incurred as revenues and accounts for out-of-pocket expenses as direct operating costs. Such amounts totaled $19.4 million and $20.8 million for the three months ended September 30, 2016 and 2015, respectively, and $55.8 million and $68.4 million for the nine months ended September 30, 2016 and 2015, respectively. Additionally, the Company typically receives a nominal handling fee, which is recognized as revenues in our consolidated statement of operations.

Use of Estimates — The preparation of consolidated condensed financial statements in accordance with accounting policies generally accepted in the United States (U.S. GAAP) requires management to make estimates and assumptions that affect our reported amounts of assets and liabilities, our disclosure of contingent assets and liabilities at the date of the consolidated condensed financial statements, and our revenues and expenses during the periods reported. Estimates are typically used when accounting for certain significant items such as legal or contractual liability accruals, mobilization and deferred mobilization, self-insured medical and dental plans, income taxes and related tax valuation allowance, and other items requiring the use of estimates. Estimates are based on a number of variables which may include third party valuations, historical experience, where applicable, and assumptions that we believe are reasonable under the circumstances. Due to the inherent uncertainty involved with estimates, actual results may differ from management estimates.

Purchase Price Allocation — We allocate the purchase price of an acquired business to its identifiable assets and liabilities in accordance with the acquisition method based on estimated fair values at the transaction date. Transaction and integration costs associated with an acquisition are expensed as incurred. The excess of the purchase price over the amount allocated to the assets and liabilities, if any, is recorded as goodwill. We use all available information to estimate fair values, including quoted market prices, the carrying value of acquired assets, and widely accepted valuation techniques such as discounted cash flows. We typically engage third-party appraisal firms to assist in fair value determination of inventories, identifiable intangible assets, and any other significant assets or liabilities. Judgments made in determining the estimated fair value assigned to each class of assets acquired and liabilities assumed, as well as asset lives, can materially impact our results of operations. See Note 2 - Acquisitions for further discussion.

Goodwill — We account for business combinations using the acquisition method of accounting. Under this method, assets and liabilities, including any remaining noncontrolling interests, are recognized at fair value at the date of acquisition. The excess of the purchase price over the fair value of assets acquired, net of liabilities assumed, plus the value of any noncontrolling interests, is recognized as goodwill. We perform our annual goodwill impairment review as of October 1 of each year, and more frequently if negative conditions or other triggering events arise. The quantitative impairment test we perform for goodwill utilizes certain assumptions, including forecasted revenue and costs assumptions. See Note 3 - Goodwill and Intangible Assets for further discussion.

Intangible Assets — Our intangible assets are related to trade names, customer relationships, and developed technology, which were acquired through acquisition and are generally amortized over a weighted average period of approximately three to six years. We assess the recoverability of the unamortized balance of our intangible assets when indicators of impairment are present based on expected future profitability and undiscounted expected cash flows and their contribution to our overall operations. Should the review indicate that the carrying value is not fully recoverable, the excess of the carrying value over the fair value of the intangible assets would be recognized as an impairment loss. See Note 3 - Goodwill and Intangible Assets for further discussion.

Impairment — We evaluate the carrying amounts of long-lived assets for potential impairment when events occur or circumstances change that indicate the carrying values of such assets may not be recoverable. We evaluate recoverability by determining the undiscounted estimated future net cash flows for the respective asset groups identified. If the sum of the estimated undiscounted cash flows is less than the carrying value of the asset group, we measure the impairment as the amount by which the assets’ carrying value exceeds the fair value of such assets. Management considers a number of factors such as estimated

8

future cash flows from the assets, appraisals and current market value analysis in determining fair value. Assets are written down to fair value if the final estimate of current fair value is below the net carrying value. The assumptions used in the impairment evaluation are inherently uncertain and require management judgment.

Concentrations of Credit Risk — Financial instruments that potentially subject the Company to concentrations of credit risk consist primarily of trade receivables with a variety of national and international oil and natural gas companies. We generally do not require collateral on our trade receivables. We depend on a limited number of significant customers. Our largest customer, Exxon Neftegas Limited (ENL), constituted approximately 39.6 percent of our consolidated revenues for the nine months ended September 30, 2016. Excluding reimbursable revenues of $54.3 million, ENL constituted approximately 28.0 percent of our total consolidated revenues for the nine months ended September 30, 2016. Our second largest customer, BP Exploration Alaska, Inc. (BP), constituted approximately 11.9 percent of our consolidated revenues for the nine months ended September 30, 2016.

At September 30, 2016 and December 31, 2015, we had deposits in domestic banks in excess of federally insured limits of approximately $69.2 million and $91.3 million, respectively. In addition, we had uninsured deposits in foreign banks as of September 30, 2016 and December 31, 2015 of $34.8 million and $44.1 million, respectively.    

Income Taxes — Income taxes are accounted for under the asset and liability method and have been provided for based upon tax laws and rates in effect in the countries in which operations are conducted and income or losses are generated. There is little or no expected relationship between the provision for or benefit from income taxes and income or loss before income taxes as the countries in which we operate have taxation regimes that vary not only with respect to nominal rate, but also in terms of the availability of deductions, credits, and other benefits. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the year in which the temporary differences are expected to be recovered or settled and the effect of changes in tax rates is recognized in income in the period in which the change is enacted. Valuation allowances are established to reduce deferred tax assets when it is more likely than not that some portion or all of the deferred tax assets will not be realized. In order to determine the amount of deferred tax assets or liabilities, as well as the valuation allowances, we must make estimates and assumptions regarding future taxable income, where rigs will be deployed and other matters. Changes in these estimates and assumptions, including changes in tax laws and other changes impacting our ability to recognize the underlying deferred tax assets, could require us to adjust the valuation allowances.

The Company recognizes the effect of income tax positions only if those positions are more likely than not to be sustained. Recognized income tax positions are measured at the largest amount that is greater than 50 percent likely of being realized and changes in recognition or measurement are reflected in the period in which the change in judgment occurs.

Legal and Investigation Matters — We accrue estimates of the probable and estimable costs for the resolution of certain legal and investigation matters. We do not accrue any amounts for other matters for which the liability is not probable and reasonably estimable.  Generally, the estimate of probable costs related to these matters is developed in consultation with our legal advisors. The estimates take into consideration factors such as the complexity of the issues, litigation risks and settlement costs. If the actual settlement costs, final judgments, or fines, after appeals, differ from our estimates, our future financial results may be adversely affected.

Note 2 - Acquisitions     

Acquisition of 2M-Tek

On April 17, 2015 we acquired 2M-Tek, a Louisiana-based manufacturer of equipment for tubular running and related well services (the 2M-Tek Acquisition) for an initial purchase price of $10.4 million paid at the closing of the acquisition, plus $8.0 million of contingent consideration payable to the seller upon the achievement of certain milestones over the 24-month period following the closing of the 2M-Tek Acquisition. The fair value of the consideration transferred was $17.2 million, which includes the $10.4 million liability paid at closing plus the estimated fair value of the contingent consideration of $6.8 million. We paid $2.0 million of the contingent consideration upon the achievement of certain milestones during the fourth quarter of 2015 and $2.0 million during the first quarter of 2016. The remaining $4.0 million of the contingent consideration was paid in April 2016.

Note 3 - Goodwill and Intangible Assets

As part of the 2M-Tek Acquisition we recognized $6.7 million of goodwill and acquired definite-lived intangible assets with an acquisition date fair value of $13.5 million. As part of the 2013 acquisition of International Tubular Services Limited (ITS) and related assets (the ITS Acquisition), we acquired definite-lived intangible assets with an acquisition date fair value of $8.5 million. All of the Company’s goodwill and intangible assets are allocated to the International Rental Tools segment.

9

Goodwill

During the 2016 second quarter, circumstances indicated that the fair value of the reporting unit may not be in excess of the carrying value of the goodwill. Therefore we performed a goodwill impairment review and determined that the fair value of the reporting unit exceeded its carrying value and therefore, no goodwill impairment was identified. Should current market conditions worsen or persist for an extended period of time, an impairment of the carrying value of our goodwill could occur. We perform our annual impairment review during the fourth quarter, as of October 1.

The change in the carrying amount of goodwill for the period ended September 30, 2016 is as follows:

Dollars in thousands	Goodwill
Balance at December 31, 2015	$	6,708
Additions	—
Balance at September 30, 2016	$	6,708

Of the total amount of goodwill recognized, zero is expected to be deductible for income tax purposes.

Intangible Assets

Intangible Assets consist of the following:

		Balance at September 30, 2016
Dollars in thousands	Estimated Useful Life (Years)	Gross Carrying Amount		Write-off Due to Sale in 2015 (1)			Accumulated Amortization			Net Carrying Amount
Amortized intangible assets:
Developed technology	6	$	11,630	$	—		$	(2,908	)	$	8,722
Customer relationships	3	5,400		(264		)	(5,136		)	—
Trade names	5	4,940		(332		)	(2,670		)	1,938
Total amortized intangible assets		$	21,970	$	(596	)	$	(10,714	)	$	10,660

(1) During the 2015 fourth quarter, we sold our controlling interest in a joint venture in Egypt resulting in the write-off of $0.6 million of intangible assets related to customer relationships and trade name acquired as part of the ITS Acquisition.

Amortization expense was $2.7 million and $3.1 million for the nine months ended September 30, 2016 and 2015, respectively.

Our remaining intangibles amortization expense for the next five years is presented below:

Dollars in thousands	Expected future intangible amortization expense
2016	$	732
2017	$	2,801
2018	$	2,306
2019	$	2,306
2020	$	2,030
Beyond 2020	$	485

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Note 4 - Earnings (Loss) Per Share (EPS)

	Three Months Ended September 30, 2016
	Income/(Loss) (Numerator)			Shares (Denominator)	Per-Share Amount
Basic EPS	$	(46,228,000	)	124,486,848	$	(0.37	)
Effect of dilutive securities:
Restricted stock units	—			—	—
Diluted EPS	$	(46,228,000	)	124,486,848	$	(0.37	)
	Nine Months Ended September 30, 2016
	Income/(Loss) (Numerator)			Shares (Denominator)	Per-Share Amount
Basic EPS	$	(181,885,000	)	123,894,980	$	(1.47	)
Effect of dilutive securities:
Restricted stock units	—			—	—
Diluted EPS	$	(181,885,000	)	123,894,980	$	(1.47	)
	Three Months Ended September 30, 2015
	Income/(Loss) (Numerator)			Shares (Denominator)	Per-Share Amount
Basic EPS	$	(48,620,000	)	122,933,518	$	(0.40	)
Effect of dilutive securities:
Restricted stock units	—			—	—
Diluted EPS	$	(48,620,000	)	122,933,518	$	(0.40	)
	Nine Months Ended September 30, 2015
	Income/(Loss) (Numerator)			Shares (Denominator)	Per-Share Amount
Basic EPS	$	(59,427,000	)	122,430,957	$	(0.49	)
Effect of dilutive securities:
Restricted stock units	—			—	—
Diluted EPS	$	(59,427,000	)	122,430,957	$	(0.49	)

For the three and nine months ended September 30, 2016 and 2015, respectively, all common shares potentially issuable in connection with outstanding restricted stock unit awards have been excluded from the calculation of diluted EPS as the company incurred losses during the three and nine month periods, therefore, inclusion of such potential common shares in the calculation would be anti-dilutive.

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Note 5 - Accumulated Other Comprehensive Income (Loss)

Accumulated other comprehensive loss consisted of the following:

Dollars in thousands	Foreign Currency Items
December 31, 2015	$	(1,888	)
Current period other comprehensive income (loss)	(4,195		)
September 30, 2016	$	(6,083	)

There were no amounts reclassified out of accumulated other comprehensive loss for the three months ended September 30, 2016. Amounts reclassified out of accumulated other comprehensive loss were $1.9 million for the nine months ended September 30, 2016 and represent realized foreign currency translation gains.

Note 6 - Reportable Segments

Our business is comprised of two business lines: (1) Drilling Services and (2) Rental Tools Services. We report our Drilling Services business as two reportable segments: (1) U.S. (Lower 48) Drilling and (2) International & Alaska Drilling. Effective July 1, 2016, we report our Rental Tools Services business as two reportable segments: (1) U.S. Rental Tools and (2) International Rental Tools. We have revised our business segment reporting to reflect our current management approach and recast prior periods to conform to the current business segment presentation.

Within the four reportable segments, we have aggregated our Arctic, Eastern Hemisphere and Latin America business units under International & Alaska Drilling, one business unit under U.S. (Lower 48) Drilling, one business unit under U.S. Rental Tools and one business unit under International Rental Tools, for a total of six business units. The Company has aggregated each of its business units in one of the four reporting segments based on the guidelines of the Financial Accounting Standards Board (FASB) Accounting Standards Codification Topic No. 280, Segment Reporting (ASC 280). We eliminate inter-segment revenues and expenses. We disclose revenues under the four reportable segments based on the similarity of the use and markets for the groups of products and services within each segment.

Drilling Services Business

In our Drilling Services business, we drill oil and gas wells for customers in both the U.S. and international markets. We provide this service with both Company-owned rigs and customer-owned rigs. We refer to the provision of drilling services with customer-owned rigs as our O&M service in which operators own their own drilling rigs but choose Parker Drilling to operate and maintain the rigs for them. The nature and scope of activities involved in drilling an oil and gas well is similar whether it is drilled with a Company-owned rig (as part of a traditional drilling contract) or a customer-owned rig (as part of an O&M contract). In addition, we provide project related services, such as engineering, procurement, project management and commissioning of customer-owned drilling facility projects. We have extensive experience and expertise in drilling geologically difficult wells and in managing the logistical and technological challenges of operating in remote, harsh and ecologically sensitive areas.

U.S. (Lower 48) Drilling

Our U.S. (Lower 48) Drilling segment provides drilling services with our GOM barge drilling rig fleet, and markets our U.S. (Lower 48) based O&M services. Our GOM barge drilling fleet operates barge rigs that drill for oil and natural gas in shallow waters in and along the inland waterways and coasts of Louisiana, Alabama and Texas. The majority of these wells are drilled in shallow water depths ranging from 6 to 12 feet. Our rigs are suitable for a variety of drilling programs, from inland coastal waters requiring shallow draft barges, to open water drilling on both state and federal water projects requiring more robust capabilities. The barge drilling industry in the GOM is characterized by cyclical activity where utilization and dayrates are typically driven by oil and gas prices and our customers’ access to project financing. Contract terms tend to be well-to-well or multi-well programs, most commonly ranging from 45 to 150 days.

International & Alaska Drilling

Our International & Alaska Drilling segment provides drilling services, with Company-owned rigs as well as through O&M contracts, and project related services. The drilling markets in which this segment operates have one or more of the following characteristics:

• customers that typically are major, independent or national oil and natural gas companies or integrated service providers;

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• drilling programs in remote locations with little infrastructure, requiring a large inventory of spare parts and other ancillary equipment and self-supported service capabilities;

• complex wells and/or harsh environments (such as high pressures, deep depths, hazardous or geologically challenging conditions and sensitive environments) requiring specialized equipment and considerable experience to drill; and

• drilling and O&M contracts that generally cover periods of one year or more.

Rental Tools Services Business

In our Rental Tools Services business, our U.S. Rental Tools and International Rental Tools segments provide premium rental equipment and services to E&P companies, drilling contractors and service companies on land and offshore in the U.S. and select international markets. Tools we provide include standard and heavy-weight drill pipe, tubing, pressure control equipment, including BOPs, drill collars and more. We also provide well construction services, which include tubular running services and downhole tools, and well intervention services, which include whipstock, fishing products and related services, as well as inspection and machine shop support. Our largest single market for rental tools is U.S. land drilling. Rental tools are used during well drilling programs and are usually rented on a daily or monthly basis.

The following table represents the results of operations by reportable segment:

	Three Months Ended   September 30,						Nine Months Ended   September 30,
Dollars in thousands	2016			2015			2016			2015
Revenues: (1)
Drilling Services:
U.S. (Lower 48) Drilling	$	1,431		$	5,961		$	4,581		$	26,906
International & Alaska Drilling	65,307			110,661			225,854			339,551
Total Drilling Services	66,738			116,622			230,435			366,457
Rental Tools Services:
U.S. Rental Tools	14,967			31,905			55,483			113,155
International Rental Tools	15,484			24,891			47,061			83,823
Total Rental Tools Services	30,451			56,796			102,544			196,978
Total revenues	97,189			173,418			332,979			563,435
Operating gross margin: (2)
Drilling Services:
U.S. (Lower 48) Drilling	(8,686		)	(7,397		)	(26,257		)	(20,673		)
International & Alaska Drilling	71			13,212			8,347			37,428
Total Drilling Services	(8,615		)	5,815			(17,910		)	16,755
Rental Tools Services:
U.S. Rental Tools	(6,645		)	2,976			(16,069		)	16,033
International Rental Tools	(6,705		)	(3,920		)	(21,639		)	371
Total Rental Tools Services	(13,350		)	(944		)	(37,708		)	16,404
Total operating gross margin	(21,965		)	4,871			(55,618		)	33,159
General and administrative expense	(7,424		)	(8,895		)	(25,200		)	(29,243		)
Provision for reduction in carrying value of certain assets	—			(906		)	—			(3,222		)
Gain (loss) on disposition of assets, net	(187		)	383			(249		)	2,686
Total operating income (loss)	(29,576		)	(4,547		)	(81,067		)	3,380
Interest expense	(11,015		)	(11,293		)	(34,764		)	(33,767		)
Interest income	9			7			48			209
Other income (loss)	(351		)	(719		)	1,776			(3,628		)
Loss from continuing operations before income taxes	$	(40,933	)	$	(16,552	)	$	(114,007	)	$	(33,806	)

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(1)For the nine months ended September 30, 2016, our largest customer, ENL, constituted approximately 39.6 percent of our total consolidated revenues and approximately 58.4 percent of our International & Alaska Drilling segment revenues. Excluding reimbursable revenues of $54.3 million, ENL constituted approximately 28.0 percent of our total consolidated revenues and approximately 45.6 percent of our International & Alaska Drilling segment revenues. Our second largest customer, BP, constituted 11.9 percent of our total consolidated revenues and approximately 17.3 percent of our International & Alaska Drilling segment revenues.

For the nine months ended September 30, 2015, our largest customer, ENL, constituted approximately 27.0 percent of our total consolidated revenues and approximately 44.7 percent of our International & Alaska Drilling segment revenues. Excluding reimbursable revenues of $58.1 million, ENL constituted approximately 19.1 percent of our total consolidated revenues and approximately 34.7 percent of our International & Alaska Drilling segment revenues.

(2)Operating gross margin is calculated as revenues less direct operating expenses, including depreciation and amortization expense.

Note 7 - Accounting for Uncertainty in Income Taxes

We apply the accounting guidance related to accounting for uncertainty in income taxes. This guidance prescribes a recognition threshold and a measurement attribute for the financial statement recognition and measurement of tax positions taken or expected to be taken in a tax return. For those benefits to be recognized, a tax position must be more likely than not to be sustained upon examination by taxing authorities. At September 30, 2016, we had a liability for unrecognized tax benefits of $6.0 million, primarily related to foreign operations, all of which would favorably impact our effective tax rate upon recognition. At December 31, 2015, we had a liability for unrecognized tax benefits of $7.8 million, including $3.6 million of benefits which would favorably impact our effective tax rate upon recognition, primarily related to foreign operations. In addition, we recognize interest and penalties that could be applied to uncertain tax positions in periodic income tax expense. As of September 30, 2016 and December 31, 2015, we had approximately $1.8 million and $3.4 million, respectively, of accrued interest and penalties related to uncertain tax positions.

Note 8 - Income Tax Expense (Benefit)

During the third quarter of 2016, we had income tax expense of $5.3 million compared with income tax expense of $31.9 million during the third quarter of 2015. Despite the pre-tax loss for the third quarter of 2016, we recognized income tax expense due to the jurisdictional mix of income and loss during the quarter, along with our continued inability to recognize the benefits associated with certain losses as a result of valuation allowances. During the 2015 third quarter, we recognized income tax expense as a result of recording a valuation allowance of $36.6 million primarily on U.S. foreign tax credits and certain foreign net operating losses.

Note 9 - Long-Term Debt

The following table illustrates our debt portfolio as of September 30, 2016 and December 31, 2015:

Dollars in thousands	September 30, 2016			December 31, 2015
6.75% Senior Notes, due July 2022	$	360,000		$	360,000
7.50% Senior Notes, due August 2020	225,000			225,000
Total principal	585,000			585,000
Less: unamortized debt issuance costs	(9,065		)	(10,202		)
Total long-term debt	$	575,935		$	574,798

6.75% Senior Notes, due July 2022

On January 22, 2014, we issued $360.0 million aggregate principal amount of 6.75% Senior Notes due 2022 (6.75% Notes) pursuant to an Indenture between the Company and The Bank of New York Mellon Trust Company, N.A., as trustee. Net proceeds from the 6.75% Notes offering plus a $40.0 million term loan draw under the Amended and Restated Senior Secured Credit Agreement (2012 Secured Credit Agreement) and cash on hand were utilized to purchase $416.2 million aggregate principal amount of our outstanding 9.125% Senior Notes due 2018 pursuant to a tender and consent solicitation offer commenced on January 7, 2014.

The 6.75% Notes are general unsecured obligations of the Company and rank equal in right of payment with all of our existing and future senior unsecured indebtedness. The 6.75% Notes are jointly and severally guaranteed by all of our subsidiaries that guarantee indebtedness under the Second Amended and Restated Senior Secured Credit Agreement, as amended from time-

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to-time (2015 Secured Credit Agreement) and our 7.50% Senior Notes due 2020 (7.50% Notes, and collectively with the 6.75% Notes, the Senior Notes). Interest on the 6.75% Notes is payable on January 15 and July 15 of each year, beginning July 15, 2014. Debt issuance costs related to the 6.75% Notes of approximately $7.6 million ($5.7 million net of amortization as of September 30, 2016) are being amortized over the term of the notes using the effective interest rate method.

At any time prior to January 15, 2017, we may redeem up to 35 percent of the aggregate principal amount of the 6.75% Notes at a redemption price of 106.75 percent of the principal amount, plus accrued and unpaid interest to the redemption date, with the net cash proceeds of certain equity offerings by us. To date we have not made any redemptions. On and after January 15, 2018, we may redeem all or a part of the 6.75% Notes upon appropriate notice, at a redemption price of 103.375 percent of the principal amount, and at redemption prices decreasing each year thereafter to par beginning January 15, 2020. If we experience certain changes in control, we must offer to repurchase the 6.75% Notes at 101.0 percent of the aggregate principal amount, plus accrued and unpaid interest and additional interest, if any, to the date of repurchase.

The Indenture restricts our ability and the ability of certain subsidiaries to: (i) sell assets, (ii) pay dividends or make other distributions on capital stock or redeem or repurchase capital stock or subordinated indebtedness, (iii) make investments, (iv) incur or guarantee additional indebtedness, (v) create or incur liens, (vi) enter into sale and leaseback transactions, (vii) incur dividend or other payment restrictions affecting subsidiaries, (viii) merge or consolidate with other entities, (ix) enter into transactions with affiliates, and (x) engage in certain business activities. Additionally, the Indenture contains certain restrictive covenants designating certain events as Events of Default. These covenants are subject to a number of important exceptions and qualifications.

7.50% Senior Notes, due August 2020

On July 30, 2013, we issued $225.0 million aggregate principal amount of the 7.50% Notes pursuant to an Indenture between the Company and The Bank of New York Mellon Trust Company, N.A., as trustee. Net proceeds from the 7.50% Notes offering were primarily used to repay the $125.0 million aggregate principal amount of a term loan used to initially finance the ITS Acquisition, to repay $45.0 million of term loan borrowings under the 2012 Secured Credit Agreement, and for general corporate purposes.

The 7.50% Notes are general unsecured obligations of the Company and rank equal in right of payment with all of our existing and future senior unsecured indebtedness. The 7.50% Notes are jointly and severally guaranteed by all of our subsidiaries that guarantee indebtedness under the 2015 Secured Credit Agreement and the 6.75% Notes. Interest on the 7.50% Notes is payable on February 1 and August 1 of each year, beginning February 1, 2014. Debt issuance costs related to the 7.50% Notes of approximately $5.6 million ($3.4 million, net of amortization as of September 30, 2016) are being amortized over the term of the notes using the effective interest rate method.

On and after August 1, 2016, we may redeem all or a part of the 7.50% Notes upon appropriate notice, at a redemption price of 103.750 percent of the principal amount, and at redemption prices decreasing each year thereafter to par beginning August 1, 2018. To date we have not made any redemptions. If we experience certain changes in control, we must offer to repurchase the 7.50% Notes at 101.0 percent of the aggregate principal amount, plus accrued and unpaid interest and additional interest, if any, to the date of repurchase.

The Indenture restricts our ability and the ability of certain subsidiaries to: (i) sell assets, (ii) pay dividends or make other distributions on capital stock or redeem or repurchase capital stock or subordinated indebtedness, (iii) make investments, (iv) incur or guarantee additional indebtedness, (v) create or incur liens, (vi) enter into sale and leaseback transactions, (vii) incur dividend or other payment restrictions affecting subsidiaries, (viii) merge or consolidate with other entities, (ix) enter into transactions with affiliates, and (x) engage in certain business activities. Additionally, the Indenture contains certain restrictive covenants designating certain events as Events of Default. These covenants are subject to a number of important exceptions and qualifications.

2015 Secured Credit Agreement

On January 26, 2015 we entered into the 2015 Secured Credit Agreement, which amended and restated the 2012 Secured Credit Agreement. The 2015 Secured Credit Agreement was originally comprised of a $200.0 million revolving credit facility (Revolver) set to mature on January 26, 2020. On June 1, 2015, we executed the first amendment to the 2015 Secured Credit Agreement in order to amend certain provisions regarding the definition of “Change of Control.” On September 29, 2015, we executed the second amendment to the 2015 Secured Credit Agreement to, among other things, (a) amend certain covenant ratios; (b) increase the Applicable Rate for certain higher levels of consolidated leverage to a maximum of 4.00 percent per annum for Eurodollar Rate loans and to 3.00 percent per annum for Base Rate loans; (c) permit multi-year letters of credit up to an aggregate amount of $5.0 million; (d) limit payment prior to September 30, 2017 of certain restricted payments and certain prepayments of unsecured senior notes and other specified forms of indebtedness; and (e) remove the option of the Company, subject to the consent of the lenders, to increase the Credit Agreement up to an additional $75 million. On May 27, 2016, we executed the third amendment to the 2015 Secured Credit Agreement (the Third Amendment), which reduced availability under the Revolver from $200 million to $100 million. Additionally, among other things, the Third Amendment: (a) eliminated the Leverage Ratio covenant until the fourth quarter of 2018 when the covenant is reinstated with the ratio established at 4.25:1.00, and remains at 4.25:1.00 thereafter;

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(b) eliminated the Consolidated Interest Coverage Ratio covenant until the fourth quarter of 2017 when the covenant is reinstated with the ratio established at 1.00:1.00 and increases by 0.25 each subsequent quarter until reaching 2.00:1.00 in the fourth quarter of 2018, and remains at 2.00:1.00 thereafter; (c) immediately increased the maximum permitted Senior Secured Leverage Ratio from 1.50:1.00 to 2.80:1.00 until it decreases to 2.20:1.00 in the second quarter of 2017, to 1.75:1.00 in the third quarter of 2017, and to 1.50:1.00 in the fourth quarter of 2017 and remains at 1.50:1.00 thereafter; (d) immediately decreased the minimum permitted Asset Coverage Ratio from 1.25:1.00 to 1.10:1.00 until it increases to 1.25: 1.00 in the fourth quarter of 2017 and remains at 1.25:1.00 thereafter; (e) requires that, at any time our Consolidated Cash Balance in U.S. bank accounts is over $50 million, we repay borrowings under the 2015 Secured Credit Agreement until our Consolidated Cash balance is no more than $50 million or all borrowings have been repaid, and (f) allows up to $75 million of Junior Lien Debt.

At the time the Third Amendment was executed, the remaining debt issuance costs for the 2015 Secured Credit Agreement totaled approximately $2.2 million. Since the Revolver was reduced by 50 percent, we wrote off approximately $1.1 million in May 2016. We incurred debt issuance costs relating to the Third Amendment of approximately $0.3 million, bringing total debt issuance costs to $1.4 million ($1.3 million, net of amortization as of September 30, 2016) which are being amortized through January 2020, or the term of the Third Amendment, on a straight line basis.

Our obligations under the 2015 Secured Credit Agreement are guaranteed by substantially all of our direct and indirect domestic subsidiaries, other than immaterial subsidiaries and subsidiaries generating revenues primarily outside the United States, each of which has executed guaranty agreements, and are secured by first priority liens on our accounts receivable, specified rigs including barge rigs in the GOM and land rigs in Alaska, certain U.S.-based rental equipment of the Company and its subsidiary guarantors and the equity interests of certain of the Company’s subsidiaries. The 2015 Secured Credit Agreement contains customary affirmative and negative covenants, such as limitations on indebtedness, liens, restrictions on entry into certain affiliate transactions and payments (including payment of dividends) and maintenance of certain ratios and coverage tests. We were in compliance with all covenants contained in the 2015 Secured Credit Agreement as of September 30, 2016.

Our Revolver is available for general corporate purposes and to support letters of credit. Interest on Revolver loans accrues at a Base Rate plus an Applicable Rate or LIBOR plus an Applicable Rate. Revolving loans are available subject to a quarterly asset coverage ratio calculation based on the Orderly Liquidation Value of certain specified rigs including barge rigs in the GOM and land rigs in Alaska, and certain U.S.-based rental equipment of the Company and its subsidiary guarantors and a percentage of eligible domestic accounts receivable. The $30.0 million draw outstanding at the closing of the 2015 Secured Credit Agreement was repaid in full during the first quarter of 2015 with cash on hand. Letters of credit outstanding against the Revolver as of September 30, 2016 totaled $9.6 million. There were no amounts drawn on the Revolver as of September 30, 2016.    

Note 10 - Fair Value of Financial Instruments

Certain of our assets and liabilities are required to be measured at fair value on a recurring basis. For purposes of recording fair value adjustments for certain financial and non-financial assets and liabilities, and determining fair value disclosures, we estimate fair value at a price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants in the principal market for the asset or liability.

The fair value measurement and disclosure requirements of FASB Accounting Standards Codification Topic No. 820, Fair Value Measurement and Disclosures (ASC 820) requires inputs that we categorize using a three-level hierarchy, from highest to lowest level of observable inputs, as follows:

• Level 1 — Unadjusted quoted prices for identical assets or liabilities in active markets;

• Level 2 — Direct or indirect observable inputs, including quoted prices or other market data, for similar assets or liabilities in active markets or identical assets or liabilities in less active markets; and

• Level 3 — Unobservable inputs that require significant judgment for which there is little or no market data.

When multiple input levels are required for a valuation, we categorize the entire fair value measurement according to the lowest level of input that is significant to the entire measurement even though we may also have utilized significant inputs that are more readily observable. The amounts reported in our consolidated balance sheets for cash and cash equivalents, accounts receivable, and accounts payable approximate fair value.

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Fair value of our debt instruments is determined using Level 2 inputs. Fair values and related carrying values of our debt instruments were as follows for the periods indicated:

	September 30, 2016				December 31, 2015
Dollars in thousands	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt
6.75% Notes	$	360,000	$	280,800	$	360,000	$	246,600
7.50% Notes	225,000		179,438		225,000		171,000
Total principal	$	585,000	$	460,238	$	585,000	$	417,600

The assets acquired and liabilities assumed in the 2M-Tek Acquisition were recorded at fair value in accordance with U.S. GAAP. Acquisition date fair values represent either Level 2 fair value measurements (current assets and liabilities, property, plant and equipment) or Level 3 fair value measurements (intangible assets).

Market conditions could cause an instrument to be reclassified from Level 1 to Level 2, or Level 2 to Level 3. There were no transfers between levels of the fair value hierarchy or any changes in the valuation techniques used during the nine months ended September 30, 2016.  

Note 11 - Commitments and Contingencies

We are a party to various lawsuits and claims arising out of the ordinary course of business. We estimate the range of our liability related to pending litigation when we believe the amount or range of loss can be estimated. We record our best estimate of a loss when the loss is considered probable. When a liability is probable and there is a range of estimated loss with no best estimate in the range, we record the minimum estimated liability related to the lawsuits or claims. As additional information becomes available, we assess the potential liability related to our pending litigation and claims and revise our estimates. Due to uncertainties related to the resolution of lawsuits and claims, the ultimate outcome may differ significantly from our estimates. In the opinion of management and based on liability accruals provided, our ultimate exposure with respect to these pending lawsuits and claims is not expected to have a material adverse effect on our consolidated financial position or cash flows, although they could have a material adverse effect on our results of operations for a particular reporting period.

Customs Agent and Foreign Corrupt Practices Act (FCPA) Settlement

On April 16, 2013, the Company and the Department of Justice (DOJ) entered into a deferred prosecution agreement (DPA), under which the DOJ deferred for three years prosecuting the Company for criminal violations of the anti-bribery provisions of the FCPA relating to the Company’s retention and use of an individual agent in Nigeria with respect to certain customs-related issues, in return for: (i) the Company’s acceptance of responsibility for, and agreement not to contest or contradict the truthfulness of, the statement of facts and allegations that have been filed in the United States District Court for the Eastern District of Virginia concurrently with the DPA; (ii) the Company’s payment of an approximately $11.76 million fine; (iii) the Company’s reaffirming its commitment to compliance with the FCPA and other applicable anti-corruption laws in connection with the Company’s operations, and continuing cooperation with domestic and foreign authorities in connection with the matters that are the subject of the DPA; (iv) the Company’s commitment to continue to address any identified areas for improvement in the Company’s internal controls, policies and procedures relating to compliance with the FCPA and other applicable anti-corruption laws if, and to the extent, not already addressed; and (v) the Company’s agreement to report to the DOJ in writing annually during the term of the DPA regarding remediation of the matters that are the subject of the DPA, implementation of any enhanced internal controls, and any evidence of improper payments the Company may have discovered during the term of the agreement. The DPA provided that as long as the Company remained in compliance with the terms of the DPA throughout its effective period, the charge against the Company would be dismissed with prejudice. The Company also settled a related civil complaint filed by the Securities and Exchange Commission. The third written annual report was filed with the DOJ on April 15, 2016, and the term of the DPA expired on April 23, 2016. On May 20, 2016, the DOJ filed a Motion to Dismiss the case based on its determination that the Company had complied with all of its obligations under the DPA. On the same date, the Court entered an Order dismissing with prejudice the United States’ case against the Company. With the dismissal of the case, the DPA was also terminated.

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Note 12 - Recent Accounting Pronouncements

In August 2016, the FASB issued Accounting Standards Update (ASU) No. 2016-15,Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments. The ASU is intended to reduce diversity in current practice regarding the manner in which certain cash receipts and cash payments are presented and classified in the cash flow statement. The standard becomes effective for public companies for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. Early adoption is permitted. We have assessed the impact of the adoption of ASU 2016-15 on our statement of cash flows, and we do not believe it will have a material impact.

In March 2016, the FASB issued ASU No. 2016-09,Compensation - Stock Compensation (Topic 718). The objective of this update is to simplify several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. The standard becomes effective for public companies for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years. Early adoption is permitted. We have assessed the impact of the adoption of ASU 2016-09 on our financial position, results of operations and cash flows, and we do not believe it will have a material impact.

In March 2016, the FASB issued ASU No. 2016-02,Leases (Topic 842). This update establishes a new lease accounting model for lessees. Upon adoption, a modified retrospective approach is required for leases that exist, or are entered into, after the beginning of the earliest comparative period presented. The standard is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, although early adoption is permitted. We are in the process of assessing the impact of the adoption of ASU 2016-02 on our financial position, results of operations and cash flows. We have not yet determined the effect of the standard on our ongoing financial reporting.

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers. This ASU supersedes the revenue recognition requirements in Accounting Standards Codification 605 - Revenue Recognition and most industry-specific guidance throughout the Codification. The standard requires that an entity recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services and should be applied retrospectively to each prior reporting period presented or retrospectively with the cumulative effect of initially applying the ASU recognized at the date of initial application. ASU 2014-09 is effective for fiscal years beginning after December 15, 2017. We are in the process of assessing the impact of the adoption of ASU 2014-09 on our financial position, results of operations and cash flows. We have not yet selected a transition method nor have we determined the effect of the standard on our ongoing financial reporting.    

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Note 13 - Parent, Guarantor, Non-Guarantor Unaudited Consolidating Condensed Financial Statements

Set forth on the following pages are the consolidating condensed financial statements of Parker Drilling. The 2015 Secured Credit Agreement and Senior Notes are fully and unconditionally guaranteed by substantially all of our direct and indirect domestic subsidiaries, other than immaterial subsidiaries and subsidiaries generating revenues primarily outside the United States, subject to the following customary release provisions:

• in connection with any sale or other disposition of all or substantially all of the assets of that guarantor (including by way of merger or consolidation) to a person that is not (either before or after giving effect to such transaction) a subsidiary of the Company;

• in connection with any sale of such amount of capital stock as would result in such guarantor no longer being a subsidiary to a person that is not (either before or after giving effect to such transaction) a subsidiary of the Company;

• if the Company designates any restricted subsidiary that is a guarantor as an unrestricted subsidiary;

• if the guarantee by a guarantor of all other indebtedness of the Company or any other guarantor is released, terminated or discharged, except by, or as a result of, payment under such guarantee; or

• upon legal defeasance or covenant defeasance (satisfaction and discharge of the indenture).

There are currently no restrictions on the ability of the restricted subsidiaries to transfer funds to Parker Drilling in the form of cash dividends, loans or advances. Parker Drilling is a holding company with no operations, other than through its subsidiaries. Separate financial statements for each guarantor company are not provided as the Company complies with Rule 3-10(f) of Regulation S-X. All guarantor subsidiaries are owned 100 percent by the parent company.

We are providing unaudited consolidating condensed financial information of the parent, Parker Drilling, the guarantor subsidiaries, and the non-guarantor subsidiaries as of September 30, 2016 and December 31, 2015 and for the three and nine months ended September 30, 2016 and 2015, respectively. The consolidating condensed financial statements present investments in both consolidated and unconsolidated subsidiaries using the equity method of accounting.

Upon the closing of our 2015 Secured Credit Agreement, one of our subsidiaries was released as a guarantor subsidiary and is now classified as a non-guarantor subsidiary. In accordance with the guidance of FASB Accounting Standards Codification Topic No. 810, Consolidation (ASC 810), we have retrospectively updated the unaudited consolidating condensed financial information as of December 31, 2015 and September 30, 2015.

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PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATING CONDENSED BALANCE SHEET

(Dollars in Thousands)

(Unaudited)

	September 30, 2016
	Parent			Guarantor			Non-Guarantor			Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	54,042		$	13,684		$	35,887		$	—		$	103,613
Accounts and notes receivable, net	—			15,637			114,979			—			130,616
Rig materials and supplies	—			(6,210		)	38,891			—			32,681
Other current assets	—			7,142			15,372			—			22,514
Total current assets	54,042			30,253			205,129			—			289,424
Property, plant and equipment, net	(19		)	483,513			234,760			—			718,254
Goodwill	—			6,708			—			—			6,708
Intangible assets, net	—			10,010			650			—			10,660
Investment in subsidiaries and intercompany advances	3,016,378			2,917,336			3,605,766			(9,539,480		)	—
Other noncurrent assets	(137,690		)	191,518			551,820			(480,812		)	124,836
Total assets	$	2,932,711		$	3,639,338		$	4,598,125		$	(10,020,292	)	$	1,149,882
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	103,855		$	33,848		$	565,881		$	(617,477	)	$	86,107
Accrued income taxes	43,043			(24,909		)	(10,948		)	—			7,186
Total current liabilities	146,898			8,939			554,933			(617,477		)	93,293
Long-term debt, net	575,935			—			—			—			575,935
Other long-term liabilities	2,867			8,418			4,876			—			16,161
Deferred tax liability	(29		)	80,545			(1,623		)	—			78,893
Intercompany payables	1,818,320			1,425,349			2,112,278			(5,355,947		)	—
Total liabilities	2,543,991			1,523,251			2,670,464			(5,973,424		)	764,282
Total equity	388,720			2,116,087			1,927,661			(4,046,868		)	385,600
Total liabilities and stockholders’ equity	$	2,932,711		$	3,639,338		$	4,598,125		$	(10,020,292	)	$	1,149,882

20

PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATING CONDENSED BALANCE SHEET

(Dollars in Thousands)

(Unaudited)

	December 31, 2015
	Parent			Guarantor			Non-Guarantor			Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	73,985		$	13,854		$	46,455		$	—		$	134,294
Accounts and notes receivable, net	—			42,261			132,844			—			175,105
Rig materials and supplies	—			(4,744		)	39,681			—			34,937
Other current assets	—			5,982			16,423			—			22,405
Total current assets	73,985			57,353			235,403			—			366,741
Property, plant and equipment, net	(19		)	543,346			262,514			—			805,841
Goodwill	—			6,708			—			—			6,708
Intangible assets, net	—			11,740			1,637			—			13,377
Investment in subsidiaries and intercompany advances	3,057,220			2,770,501			3,319,702			(9,147,423		)	—
Other noncurrent assets	(234,786		)	312,790			265,995			(169,964		)	174,035
Total assets	$	2,896,400		$	3,702,438		$	4,085,251		$	(9,317,387	)	$	1,366,702
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	84,456		$	56,382		$	295,439		$	(306,574	)	$	129,703
Accrued income taxes	9,900			2,111			(5,593		)	—			6,418
Total current liabilities	94,356			58,493			289,846			(306,574		)	136,121
Long-term debt, net	574,798			—			—			—			574,798
Other long-term liabilities	2,868			7,446			8,303			—			18,617
Deferred tax liability	(29		)	69,679			(996		)	—			68,654
Intercompany payables	1,656,968			1,401,510			1,864,671			(4,923,149		)	—
Total liabilities	2,328,961			1,537,128			2,161,824			(5,229,723		)	798,190
Total equity	567,439			2,165,310			1,923,427			(4,087,664		)	568,512
Total liabilities and stockholders’ equity	$	2,896,400		$	3,702,438		$	4,085,251		$	(9,317,387	)	$	1,366,702

21

PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATING CONDENSED STATEMENT OF OPERATIONS

(Dollars in Thousands)

(Unaudited)

	Three Months Ended September 30, 2016
	Parent			Guarantor			Non-Guarantor			Eliminations			Consolidated
Total revenues	$	—		$	25,399		$	96,663		$	(24,873	)	$	97,189
Operating expenses	—			25,505			84,048			(24,873		)	84,680
Depreciation and amortization	—			22,300			12,174			—			34,474
Total operating gross margin (loss)	—			(22,406		)	441			—			(21,965		)
General and administration expense (1)	(92		)	(2,759		)	(4,573		)	—			(7,424		)
Provision for reduction in carrying value of certain assets	—			—			—			—			—
Gain (loss) on disposition of assets, net	—			(12		)	(175		)	—			(187		)
Total operating income (loss)	(92		)	(25,177		)	(4,307		)	—			(29,576		)
Other income (expense):
Interest expense	(11,700		)	(56		)	504			237			(11,015		)
Interest income	189			157			(100		)	(237		)	9
Other	—			15			(366		)	—			(351		)
Equity in net earnings of subsidiaries	(24,887		)	—			—			24,887			—
Total other income (expense)	(36,398		)	116			38			24,887			(11,357		)
Income (loss) before income taxes	(36,490		)	(25,061		)	(4,269		)	24,887			(40,933		)
Total income tax expense (benefit)	9,738			(6,652		)	2,209			—			5,295
Net income (loss) attributable to controlling interest	$	(46,228	)	$	(18,409	)	$	(6,478	)	$	24,887		$	(46,228	)

(1) General and administration expenses for field operations are included in operating expenses.

22

PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATING CONDENSED STATEMENT OF OPERATIONS

(Dollars in Thousands)

(Unaudited)

	Three Months Ended September 30, 2015
	Parent			Guarantor			Non-Guarantor			Eliminations			Consolidated
Total revenues	$	—		$	59,252		$	138,564		$	(24,398	)	$	173,418
Operating expenses	—			32,457			120,904			(24,398		)	128,963
Depreciation and amortization	—			24,002			15,582			—			39,584
Total operating gross margin (loss)	—			2,793			2,078			—			4,871
General and administration expense (1)	(148		)	(8,857		)	110			—			(8,895		)
Provision for reduction in carrying value of certain assets	—			(920		)	14			—			(906		)
Gain (loss) on disposition of assets, net	—			407			(24		)	—			383
Total operating income (loss)	(148		)	(6,577		)	2,178			—			(4,547		)
Other income (expense):
Interest expense	(11,020		)	(268		)	(2,618		)	2,613			(11,293		)
Interest income	173			(18		)	2,465			(2,613		)	7
Other	—			(102		)	(617		)	—			(719		)
Equity in net earnings of subsidiaries	(29,913		)	—			—			29,913			—
Total other income (expense)	(40,760		)	(388		)	(770		)	29,913			(12,005		)
Income (loss) before income taxes	(40,908		)	(6,965		)	1,408			29,913			(16,552		)
Income tax expense (benefit)	7,712			(2,846		)	27,064			—			31,930
Net income (loss)	(48,620		)	(4,119		)	(25,656		)	29,913			(48,482		)
Less: Net income (loss) attributable to noncontrolling interest	—			—			138			—			138
Net income (loss) attributable to controlling interest	$	(48,620	)	$	(4,119	)	$	(25,794	)	$	29,913		$	(48,620	)

(1) General and administration expenses for field operations are included in operating expenses.

23

PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATING CONDENSED STATEMENT OF OPERATIONS

(Dollars in Thousands)

(Unaudited)

	Nine Months Ended September 30, 2016
	Parent			Guarantor			Non-Guarantor			Eliminations			Consolidated
Total revenues	$	—		$	107,368		$	292,034		$	(66,423	)	$	332,979
Operating expenses	—			83,917			264,498			(66,423		)	281,992
Depreciation and amortization	—			68,739			37,866			—			106,605
Total operating gross margin (loss)	—			(45,288		)	(10,330		)	—			(55,618		)
General and administration expense (1)	(291		)	(20,199		)	(4,710		)	—			(25,200		)
Gain (loss) on disposition of assets, net	—			141			(390		)	—			(249		)
Total operating income (loss)	(291		)	(65,346		)	(15,430		)	—			(81,067		)
Other income (expense):
Interest expense	(36,452		)	(537		)	(4,646		)	6,871			(34,764		)
Interest income	584			515			5,820			(6,871		)	48
Other	—			488			1,288			—			1,776
Equity in net earnings of subsidiaries	(65,679		)	—			—			65,679			—
Total other income (expense)	(101,547		)	466			2,462			65,679			(32,940		)
Income (loss) before income taxes	(101,838		)	(64,880		)	(12,968		)	65,679			(114,007		)
Total income tax expense (benefit)	80,047			(15,656		)	3,487			—			67,878
Net income (loss) attributable to controlling interest	$	(181,885	)	$	(49,224	)	$	(16,455	)	$	65,679		$	(181,885	)

(1) General and administration expenses for field operations are included in operating expenses.

24

PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATING CONDENSED STATEMENT OF OPERATIONS

(Dollars in Thousands)

(Unaudited)

	Nine Months Ended September 30, 2015
	Parent			Guarantor			Non-Guarantor			Eliminations			Consolidated
Total revenues	$	—		$	201,924		$	452,197		$	(90,686	)	$	563,435
Operating expenses	—			112,229			390,259			(90,686		)	411,802
Depreciation and amortization	—			71,270			47,204			—			118,474
Total operating gross margin (loss)	—			18,425			14,734			—			33,159
General and administration expense (1)	(1,152		)	(31,896		)	3,805			—			(29,243		)
Provision for reduction in carrying value of certain assets	—			(920		)	(2,302		)	—			(3,222		)
Gain on disposition of assets, net	—			452			2,234			—			2,686
Total operating income (loss)	(1,152		)	(13,939		)	18,471			—			3,380
Other income (expense):
Interest expense	(33,145		)	(608		)	(5,956		)	5,942			(33,767		)
Interest income	756			(12		)	5,407			(5,942		)	209
Other	—			(81		)	(3,547		)	—			(3,628		)
Equity in net earnings of subsidiaries	(29,316		)	—			—			29,316			—
Total other income (expense)	(61,705		)	(701		)	(4,096		)	29,316			(37,186		)
Income (loss) before income taxes	(62,857		)	(14,640		)	14,375			29,316			(33,806		)
Total income tax expense (benefit)	(3,430		)	(5,656		)	33,918			—			24,832
Net income (loss)	(59,427		)	(8,984		)	(19,543		)	29,316			(58,638		)
Less: Net income (loss) attributable to noncontrolling interest	—			—			789			—			789
Net income (loss) attributable to controlling interest	$	(59,427	)	$	(8,984	)	$	(20,332	)	$	29,316		$	(59,427	)

(1) General and administration expenses for field operations are included in operating expenses.

25

PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATING CONDENSED STATEMENT OF COMPREHENSIVE INCOME (LOSS)

(Dollars in Thousands)

(Unaudited)

	Three Months Ended September 30, 2016
	Parent			Guarantor			Non-Guarantor			Eliminations		Consolidated
Comprehensive income (loss):
Net income (loss)	$	(46,228	)	$	(18,409	)	$	(6,478	)	$	24,887	$	(46,228	)
Other comprehensive income (loss), net of tax:
Currency translation difference on related borrowings	—			—			116			—		116
Currency translation difference on foreign currency net investments	—			—			(740		)	—		(740		)
Total other comprehensive income (loss), net of tax:	—			—			(624		)	—		(624		)
Comprehensive income (loss) attributable to controlling interest	$	(46,228	)	$	(18,409	)	$	(7,102	)	$	24,887	$	(46,852	)

PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATING CONDENSED STATEMENT OF COMPREHENSIVE INCOME (LOSS)

(Dollars in Thousands)

(Unaudited)

	Three Months Ended September 30, 2015
	Parent			Guarantor			Non-Guarantor			Eliminations		Consolidated
Comprehensive income (loss):
Net income (loss)	$	(48,620	)	$	(4,119	)	$	(25,656	)	$	29,913	$	(48,482	)
Other comprehensive income (loss), net of tax:
Currency translation difference on related borrowings	—			—			(1,285		)	—		(1,285		)
Currency translation difference on foreign currency net investments	—			—			588			—		588
Total other comprehensive income (loss), net of tax:	—			—			(697		)	—		(697		)
Comprehensive income (loss)	(48,620		)	(4,119		)	(26,353		)	29,913		(49,179		)
Comprehensive income (loss) attributable to noncontrolling interest	—			—			(82		)	—		(82		)
Comprehensive income (loss) attributable to controlling interest	$	(48,620	)	$	(4,119	)	$	(26,435	)	$	29,913	$	(49,261	)

26

PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATING CONDENSED STATEMENT OF COMPREHENSIVE INCOME (LOSS)

(Dollars in Thousands)

(Unaudited)

	Nine Months Ended September 30, 2016
	Parent			Guarantor			Non-Guarantor			Eliminations		Consolidated
Comprehensive income (loss):
Net income (loss)	$	(181,885	)	$	(49,224	)	$	(16,455	)	$	65,679	$	(181,885	)
Other comprehensive income (loss), net of tax:
Currency translation difference on related borrowings	—			—			311			—		311
Currency translation difference on foreign currency net investments	—			—			(4,506		)	—		(4,506		)
Total other comprehensive income (loss), net of tax:	—			—			(4,195		)	—		(4,195		)
Comprehensive income (loss) attributable to controlling interest	$	(181,885	)	$	(49,224	)	$	(20,650	)	$	65,679	$	(186,080	)

PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATING CONDENSED STATEMENT OF COMPREHENSIVE INCOME (LOSS)

(Dollars in Thousands)

(Unaudited)

	Nine Months Ended September 30, 2015
	Parent			Guarantor			Non-Guarantor			Eliminations		Consolidated
Comprehensive income (loss):
Net income (loss)	$	(59,427	)	$	(8,984	)	$	(19,543	)	$	29,316	$	(58,638	)
Other comprehensive income (loss), net of tax:
Currency translation difference on related borrowings	—			—			(2,308		)	—		(2,308		)
Currency translation difference on foreign currency net investments	—			—			1,462			—		1,462
Total other comprehensive income (loss), net of tax:	—			—			(846		)	—		(846		)
Comprehensive income (loss)	(59,427		)	(8,984		)	(20,389		)	29,316		(59,484		)
Comprehensive income (loss) attributable to noncontrolling interest	—			—			(571		)	—		(571		)
Comprehensive income (loss) attributable to controlling interest	$	(59,427	)	$	(8,984	)	$	(20,960	)	$	29,316	$	(60,055	)

27

PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)

(Unaudited)

	Nine Months Ended September 30, 2016
	Parent			Guarantor			Non-Guarantor			Eliminations			Consolidated
Cash flows from operating activities:
Net income (loss)	$	(181,885	)	$	(49,224	)	$	(16,455	)	$	65,679		$	(181,885	)
Adjustments to reconcile net income (loss):
Depreciation and amortization	—			68,739			37,866			—			106,605
Accretion of contingent consideration	—			419			—			—			419
(Gain) loss on debt modification	1,088			—			—			—			1,088
(Gain) loss on disposition of assets	—			(141		)	390			—			249
Deferred income tax expense (benefit)	46,773			12,693			1,733			—			61,199
Expenses not requiring cash	4,155			(505		)	(7,681		)	—			(4,031		)
Equity in net earnings of subsidiaries	65,679			—			—			(65,679		)	—
Change in assets and liabilities:
Accounts and notes receivable	—			26,956			17,843			—			44,799
Other assets	(113,372		)	119,703			(3,049		)	—			3,282
Accounts payable and accrued liabilities	(7,079		)	(16,486		)	(7,025		)	—			(30,590		)
Accrued income taxes	33,313			(27,191		)	(8,114		)	—			(1,992		)
Net cash provided by (used in) operating activities	(151,328		)	134,963			15,508			—			(857		)
Cash flows from investing activities:
Capital expenditures	—			(10,121		)	(10,873		)	—			(20,994		)
Proceeds from the sale of assets	—			435			1,861			—			2,296
Net cash provided by (used in) investing activities	—			(9,686		)	(9,012		)	—			(18,698		)
Cash flows from financing activities:
Payment for noncontrolling interest	(3,375		)	—			—			—			(3,375		)
Payment of contingent consideration	—			(6,000		)	—			—			(6,000		)
Excess tax benefit from stock-based compensation	(1,751		)	—			—			—			(1,751		)
Intercompany advances, net	136,511			(119,447		)	(17,064		)	—			—
Net cash provided by (used in) financing activities	131,385			(125,447		)	(17,064		)	—			(11,126		)
Net change in cash and cash equivalents	(19,943		)	(170		)	(10,568		)	—			(30,681		)
Cash and cash equivalents at beginning of year	73,985			13,854			46,455			—			134,294
Cash and cash equivalents at end of year	$	54,042		$	13,684		$	35,887		$	—		$	103,613

28

PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)

(Unaudited)

	Nine Months Ended September 30, 2015
	Parent			Guarantor			Non-Guarantor			Eliminations			Consolidated
Cash flows from operating activities:
Net income (loss)	$	(59,427	)	$	(8,984	)	$	(19,543	)	$	29,316		$	(58,638	)
Adjustments to reconcile net income (loss)
Depreciation and amortization	—			71,270			47,204			—			118,474
Accretion of contingent consideration	—			—			547			—			547
Provision for reduction in carrying value of certain assets	—			920			2,302			—			3,222
(Gain) loss on disposition of assets	—			(452		)	(2,234		)	—			(2,686		)
Deferred income tax expense (benefit)	(24,184		)	10,032			24,411			—			10,259
Expenses not requiring cash	6,498			2,677			(1,146		)	—			8,029
Equity in net earnings of subsidiaries	29,316			—			—			(29,316		)	—
Change in assets and liabilities:
Accounts and notes receivable	(33		)	36,694			14,593			—			51,254
Other assets	(121,465		)	110,017			12,934			—			1,486
Accounts payable and accrued liabilities	(10,480		)	(168		)	(5,142		)	—			(15,790		)
Accrued income taxes	6,481			(2,081		)	(11,705		)	—			(7,305		)
Net cash provided by (used in) operating activities	(173,294		)	219,925			62,221			—			108,852
Cash flows from investing activities:
Capital expenditures	—			(50,396		)	(22,073		)	—			(72,469		)
Proceeds from the sale of assets	—			489			242			—			731
Proceeds from insurance settlements	—			—			2,500			—			2,500
Acquisitions, net of cash acquired	—			(10,431		)	—			—			(10,431		)
Net cash provided by (used in) investing activities	—			(60,338		)	(19,331		)	—			(79,669		)
Cash flows from financing activities:
Repayments of long-term debt	(30,000		)	—			—			—			(30,000		)
Payment of debt issuance costs	(1,996		)	—			—			—			(1,996		)
Excess tax benefit from stock-based compensation	(992		)	—			—			—			(992		)
Intercompany advances, net	216,082			(165,133		)	(50,949		)	—			—
Net cash provided by (used in) financing activities	183,094			(165,133		)	(50,949		)	—			(32,988		)
Net change in cash and cash equivalents	9,800			(5,546		)	(8,059		)	—			(3,805		)
Cash and cash equivalents at beginning of year	36,728			13,546			58,182			—			108,456
Cash and cash equivalents at end of year	$	46,528		$	8,000		$	50,123		$	—		$	104,651

29

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

Management’s discussion and analysis should be read in conjunction with Item 1. Financial Statements of this quarterly report on Form 10-Q and with our Annual Report on Form 10-K for the year ended December 31, 2015 (2015 Form 10-K).

Executive Summary

The oil and gas industry is highly cyclical. Activity levels are driven by traditional energy industry activity indicators, which include current and expected commodity prices, drilling rig counts, footage drilled, well counts, and our customers’ spending levels allocated to exploratory and development drilling.

Historical market indicators are listed below:

	Nine Months Ended Sept 30,
	2016		2015	% Change
Worldwide Rig Count (1)
U.S. (land and offshore)	485		1,052	(54	)%
International (2)	965		1,187	(19	)%
Commodity Prices (3)
Crude Oil (United Kingdom Brent)	$	43.17	56.60	(24	)%
Crude Oil (West Texas Intermediate)	$	41.53	51.01	(19	)%
Natural Gas (Henry Hub)	$	2.35	2.76	(15	)%

(1) Estimate of drilling activity measured by the average active rig count for the periods indicated - Source: Baker Hughes Incorporated Rig Count.

(2) Excludes Canadian Rig Count.

(3) Average daily commodity prices for the periods indicated based on NYMEX front-month composite energy prices.

In the 2016 third quarter, we saw a continuation of the weak market conditions that have persisted since the downturn began. As a result, for the three and nine months ended September 30, 2016, our revenues and gross margins came in lower compared with the same periods in the prior year. However, our 2016 third quarter results benefited as we began generating revenues on two O&M contracts in the Atlantic Coast, Canada and Sakhalin Island, Russia. These new revenue streams will provide additional revenues going forward as we continue to ramp-up activities.

Financial Results

In the 2016 third quarter we generated revenues of $97.2 million, a decrease of $76.2 million, or 43.9 percent, compared with the 2015 third quarter. In the first nine months of 2016, revenues totaled $333.0 million, a decrease of $230.4 million, or 40.9 percent. All of our segments experienced revenue declines for the three and nine months ended September 30, 2016 primarily driven by reduced customer spending and consistent with the declines in worldwide rig count and commodity prices. The International & Alaska Drilling segment was the largest driver of the year-over-year decline in both the three and nine months ended September 30, 2016, primarily due to a decline in utilization and reduced revenues per day.

Outlook

While there are indications market conditions are stabilizing and we may continue to see conditions improve in the near future, our expectations for the pace of the recovery remain guarded. We have taken steps to align resources with the ongoing market downturn by lowering our cost base and managing our cash and liquidity. We ended the 2016 third quarter with $194.0 million of liquidity. We will continue to adjust and adapt to the business environment and market conditions, while remaining opportunistic and positioning the Company for longer-term growth.

For our U.S. (Lower 48) Drilling segment, we do not anticipate any material changes in near-term activity levels, so we expect to see a continuation of low barge utilization levels and dayrates. However, we have had discussions with customers about multi-well opportunities in 2017 for the first time since the downturn began, and we continue to see U.S. land rig count move higher. In the International & Alaska Drilling segment, we expect activity to remain flat through the last quarter of 2016, although we are seeing an increase in rig tendering activity for work in the second half of 2017.

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For our U.S. Rental Tools segment, while overall U.S. drilling activity is showing signs of improvement, we expect further declines in U.S. offshore revenues that will be partially offset by increased U.S. land activity. For our International Rental Tools segment, we expect a slight improvement in results due to increased activity and further cost management.

Results of Operations

Our business is comprised of two business lines: (1) Drilling Services and (2) Rental Tools Services. We report our Drilling Services business as two reportable segments: (1) U.S. (Lower 48) Drilling and (2) International & Alaska Drilling. Effective July 1, 2016, we report our Rental Tools Services business as two reportable segments: (1) U.S. Rental Tools and (2) International Rental Tools. We have revised our business segment reporting to reflect our current management approach and recast prior periods to conform to the current business segment presentation. We eliminate inter-segment revenues and expenses.

We analyze financial results for each of our reportable segments. The reportable segments presented are consistent with our reportable segments discussed in Note 6 to our consolidated condensed financial statements. We monitor our reporting segments based on several criteria, including operating gross margin and operating gross margin excluding depreciation and amortization. Operating gross margin excluding depreciation and amortization is computed as revenues less direct operating expenses, and excludes depreciation and amortization expense, where applicable. Operating gross margin percentages are computed as operating gross margin as a percent of revenues. The operating gross margin excluding depreciation and amortization amounts and percentages should not be used as a substitute for those amounts reported under accounting policies generally accepted in the United States (U.S. GAAP), but should be viewed in addition to the Company’s reported results prepared in accordance with U.S. GAAP. Management believes this information provides valuable insight into the information management considers important in managing the business.

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

Revenues decreased $76.2 million, or 43.9 percent, to $97.2 million for the three months ended September 30, 2016 as compared with revenues of $173.4 million for the three months ended September 30, 2015. Operating gross margin decreased $26.9 million to a loss of $22.0 million for the three months ended September 30, 2016 as compared with income of $4.9 million for the three months ended September 30, 2015.

    The following is an analysis of our operating results for the comparable periods by reportable segment:

	Three Months Ended September 30,
Dollars in Thousands	2016					2015
Revenues:
Drilling Services:
U.S. (Lower 48) Drilling	$	1,431		2	%	$	5,961		3	%
International & Alaska Drilling	65,307			67	%	110,661			64	%
Total Drilling Services	66,738			69	%	116,622			67	%
Rental Tools Services:
U.S. Rental Tools	14,967			15	%	31,905			19	%
International Rental Tools	15,484			16	%	24,891			14	%
Total Rental Tools Services	30,451			31	%	56,796			33	%
Total revenues	97,189			100	%	173,418			100	%
Operating gross margin (loss) excluding depreciation and amortization:
Drilling Services:
U.S. (Lower 48) Drilling	(3,681		)	n/m		(1,859		)	n/m
International & Alaska Drilling	13,625			21	%	29,075			26	%
Total Drilling Services	9,944			15	%	27,216			23	%
Rental Tools Services:
U.S. Rental Tools	4,221			28	%	14,903			47	%
International Rental Tools	(1,656		)	n/m		2,336			9	%
Total Rental Tools Services	2,565			8	%	17,239			30	%
Total operating gross margin (loss) excluding depreciation and amortization	12,509			13	%	44,455			26	%
Depreciation and amortization	(34,474		)			(39,584		)
Total operating gross margin (loss)	(21,965		)			4,871
General and administrative expense	(7,424		)			(8,895		)
Provision for reduction in carrying value of certain assets	—					(906		)
Gain (loss) on disposition of assets, net	(187		)			383
Total operating income (loss)	$	(29,576	)			$	(4,547	)

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Operating gross margin amounts are reconciled to our most comparable U.S. GAAP measure as follows:

Dollars in Thousands	U.S. (Lower 48) Drilling			International & Alaska Drilling		U.S. Rental Tools			International Rental Tools			Total
Three Months Ended September 30, 2016
Operating gross margin (loss) (1)	$	(8,686	)	$	71	$	(6,645	)	$	(6,705	)	$	(21,965	)
Depreciation and amortization	5,005			13,554		10,866			5,049			34,474
Operating gross margin (loss) excluding depreciation and amortization	$	(3,681	)	$	13,625	$	4,221		$	(1,656	)	$	12,509
Three Months Ended September 30, 2015
Operating gross margin (loss) (1)	$	(7,397	)	$	13,212	$	2,976		$	(3,920	)	$	4,871
Depreciation and amortization	5,538			15,863		11,927			6,256			39,584
Operating gross margin (loss) excluding depreciation and amortization	$	(1,859	)	$	29,075	$	14,903		$	2,336		$	44,455

(1) Operating gross margin (loss) is calculated as revenues less direct operating expenses, including depreciation and amortization expense.

The following table presents our average utilization rates and rigs available for service for the three months ended September 30, 2016 and 2015, respectively:

	Three Months Ended September 30,
	2016		2015
U.S. (Lower 48) Drilling
Rigs available for service (1)	13.0		13.0
Utilization rate of rigs available for service (2)	6	%	16	%
International & Alaska Drilling
Eastern Hemisphere
Rigs available for service (1)	13.0		13.0
Utilization rate of rigs available for service (2)	37	%	59	%
Latin America Region
Rigs available for service (1)	7.0		9.0
Utilization rate of rigs available for service (2)	22	%	44	%
Alaska
Rigs available for service (1)	2.0		2.0
Utilization rate of rigs available for service (2)	100	%	100	%
Total International & Alaska Drilling
Rigs available for service (1)	22.0		24.0
Utilization rate of rigs available for service (2)	38	%	57	%

(1) The number of rigs available for service is determined by calculating the number of days each rig was in our fleet and was under contract or available for contract. For example, a rig under contract or available for contract for six months of a year is 0.5 rigs available for service during such year. Our method of computation of rigs available for service may not be comparable to other similarly titled measures of other companies.

(2) Rig utilization rates are based on a weighted average basis assuming total days availability for all rigs available for service. Rigs acquired or disposed of are treated as added to or removed from the rig fleet as of the date of acquisition or disposal. Rigs that are in operation or fully or partially staffed and on a revenue-producing standby status are considered to be utilized. Rigs under contract that generate revenues during moves between locations or during mobilization or demobilization are also considered to be utilized. Our method of computation of rig utilization may not be comparable to other similarly titled measures of other companies.

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Drilling Services Business

U.S. (Lower 48) Drilling

U.S. (Lower 48) Drilling segment revenues decreased $4.6 million, or 76.7 percent, to $1.4 million for the third quarter of 2016 compared with revenues of $6.0 million for the third quarter of 2015. The decrease was primarily due to lower utilization driven by continued substantial reductions in drilling activity by operators in the inland waters of the Gulf of Mexico (GOM) resulting from lower oil prices. Utilization declined to 6.0 percent for the quarter ended September 30, 2016 from 16.0 percent for the quarter ended September 30, 2015, resulting in a $3.2 million decrease in revenues. The remainder of the decrease in revenues was due to our O&M contract supporting three platform operations located offshore California that ended during the 2015 fourth quarter, as well as reduced dayrates and reimbursable revenues in the third quarter of 2016.

U.S. (Lower 48) Drilling segment operating gross margin excluding depreciation and amortization decreased $1.8 million to a loss of $3.7 million for the third quarter of 2016 compared with a loss of $1.9 million for the third quarter of 2015. The decrease was primarily due to the decline in utilization and reduced dayrates discussed above.

International & Alaska Drilling

International & Alaska Drilling segment revenues decreased $45.4 million, or 41.0 percent, to $65.3 million for the third quarter of 2016 compared with $110.7 million for the third quarter of 2015.

The decrease in revenues was primarily due to the following:

• a decrease of $19.1 million resulting from decreased utilization for Company-owned rigs driven by the decline in oil prices resulting in reduced customer activity. Utilization for the segment decreased to 38.0 percent for the quarter ended September 30, 2016 from 57.0 percent for the quarter ended September 30, 2015;

• a decrease of $9.7 million driven by a decline in revenues per day resulting from certain Company-owned and customer-owned rigs shifting to standby mode during 2016 and remaining in standby mode during the third quarter of 2016 compared with operating mode during the third quarter of 2015, as well as a reduction in average dayrates due to pricing pressures from customers resulting from the decline in oil prices;

• a decrease of $9.3 million in revenues related to our project services activities; and

• a decrease of $4.4 million related to revenues earned from mobilization and demobilization activities.

International & Alaska Drilling segment operating gross margin excluding depreciation and amortization decreased $15.5 million, or 53.3 percent, to $13.6 million for the third quarter of 2016 compared with $29.1 million for the third quarter of 2015. The decrease in operating gross margin excluding depreciation and amortization was primarily due to the impact of the reduced utilization and reduced revenues per day discussed above.

Rental Tools Services Business

U.S. Rental Tools

U.S. Rental Tools segment revenues decreased $16.9 million, or 53.0 percent, to $15.0 million for the third quarter of 2016 compared with $31.9 million for the third quarter of 2015. The decrease was primarily driven by continued reduction in customer activity and pricing pressures resulting from lower oil prices impacting both U.S. land and offshore GOM rentals.

U.S. Rental Tools segment operating gross margin excluding depreciation and amortization decreased $10.7 million, or 71.8 percent, to $4.2 million in the third quarter of 2016 compared with $14.9 million for the third quarter of 2015. The decrease was due to the declines in oil prices and customer activity discussed above, partially offset by lower operating costs resulting from cost reduction efforts.

International Rental Tools

International Rental Tools segment revenues decreased $9.4 million, or 37.8 percent, to $15.5 million for the third quarter of 2016 compared with $24.9 million for the third quarter of 2015. The decrease was primarily attributable to the continued reduction in customer activity and price erosion, resulting from lower oil prices across most of our markets, with the largest declines in our United Kingdom (U.K.) North Sea and Asia Pacific operations.

International Rental Tools segment operating gross margin excluding depreciation and amortization decreased $4.0 million, or 173.9 percent, to a loss of $1.7 million in the third quarter of 2016 compared with gross margin of $2.3 million for the

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third quarter of 2015. The decrease was due to the declines in oil prices and customer activity discussed above, partially offset by lower operating costs resulting from cost reduction efforts.

Other Financial Data

General and administrative expense

General and administration expense decreased $1.5 million to $7.4 million for the third quarter of 2016, compared with $8.9 million for the third quarter of 2015 primarily due to reduced personnel costs resulting from cost savings initiatives.

Provision for reduction in carrying value of certain assets

There was no provision for reduction in carrying value of certain assets recorded during the third quarter of 2016 compared with a $0.9 million provision for reduction in carrying value recorded during the third quarter of 2015. The provision during the third quarter of 2015 related to certain assets in our International & Alaska Drilling segment. Management concluded due to changing market conditions the carrying value of the assets was no longer recoverable.

Gain (loss) on disposition of assets

Net losses recognized on asset dispositions were $0.2 million for the third quarter of 2016 as compared with net gains of $0.4 million for the third quarter of 2015. Activity in both periods included the results of asset sales. We periodically sell equipment deemed to be excess, obsolete, or not currently required for operations.

Interest income and expense

Interest expense decreased $0.3 million to $11.0 million for the third quarter of 2016 compared with $11.3 million for the third quarter of 2015. This decrease in interest expense was primarily driven by $0.3 million of accretion of contingent consideration recorded in the second quarter of 2015 that did not recur in the second quarter of 2016, as the contingent consideration had been fully paid as of April 2016. Interest income during each of the 2016 and 2015 third quarters was nominal.

Other income and expense

Other expense was $0.4 million and $0.7 million for the third quarters of 2016 and 2015, respectively. Other expense for the third quarters of 2016 and 2015 included the impact of foreign currency fluctuations.

Income tax expense (benefit)

During the third quarter of 2016, we had income tax expense of $5.3 million compared with income tax expense of $31.9 million during the third quarter of 2015. Despite the pre-tax loss for the third quarter of 2016, we recognized income tax expense due to the jurisdictional mix of income and loss during the quarter, along with our continued inability to recognize the benefits associated with certain losses as a result of valuation allowances. During the 2015 third quarter, we recognized income tax expense as a result of recording a valuation allowance of $36.6 million, primarily on U.S. foreign tax credits and certain foreign net operating losses.

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

Revenues decreased $230.4 million, or 40.9 percent, to $333.0 million for the nine months ended September 30, 2016 as compared with revenues of $563.4 million for the nine months ended September 30, 2015. Operating gross margin decreased $88.8 million to a loss of $55.6 million for the nine months ended September 30, 2016 as compared with income of $33.2 million for the nine months ended September 30, 2015.

    The following is an analysis of our operating results for the comparable periods by reportable segment:

	Nine Months Ended September 30,
Dollars in Thousands	2016					2015
Revenues:
Drilling Services:
U.S. (Lower 48) Drilling	$	4,581		1	%	$	26,906		5	%
International & Alaska Drilling	225,854			68	%	339,551			60	%
Total Drilling Services	230,435			69	%	366,457			65	%
Rental Tools Services:
U.S. Rental Tools	55,483			17	%	113,155			20	%
International Rental Tools	47,061			14	%	83,823			15	%
Total Rental Tools Services	102,544			31	%	196,978			35	%
Total revenues	332,979			100	%	563,435			100	%
Operating gross margin (loss) excluding depreciation and amortization:
Drilling Services:
U.S. (Lower 48) Drilling	(10,920		)	n/m		(3,724		)	n/m
International & Alaska Drilling	50,337			22	%	87,107			26	%
Total Drilling Services	39,417			17	%	83,383			23	%
Rental Tools Services:
U.S. Rental Tools	17,368			31	%	51,693			46	%
International Rental Tools	(5,798		)	n/m		16,557			20	%
Total Rental Tools Services	11,570			11	%	68,250			35	%
Total operating gross margin (loss) excluding depreciation and amortization	50,987			15	%	151,633			27	%
Depreciation and amortization	(106,605		)			(118,474		)
Total operating gross margin (loss)	(55,618		)			33,159
General and administrative expense	(25,200		)			(29,243		)
Provision for reduction in carrying value of certain assets	—					(3,222		)
Gain (loss) on disposition of assets, net	(249		)			2,686
Total operating income (loss)	$	(81,067	)			$	3,380

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Operating gross margin amounts are reconciled to our most comparable U.S. GAAP measure as follows:

Dollars in Thousands	U.S. (Lower 48) Drilling			International & Alaska Drilling		U.S. Rental Tools			International Rental Tools			Total
Nine Months Ended September 30, 2016
Operating gross margin (loss) (1)	$	(26,257	)	$	8,347	$	(16,069	)	$	(21,639	)	$	(55,618	)
Depreciation and amortization	15,337			41,990		33,437			15,841			106,605
Operating gross margin (loss) excluding depreciation and amortization	$	(10,920	)	$	50,337	$	17,368		$	(5,798	)	$	50,987
Nine Months Ended September 30, 2015
Operating gross margin (loss) (1)	$	(20,673	)	$	37,428	$	16,033		$	371		$	33,159
Depreciation and amortization	16,949			49,679		35,660			16,186			118,474
Operating gross margin (loss) excluding depreciation and amortization	$	(3,724	)	$	87,107	$	51,693		$	16,557		$	151,633

(1) Operating gross margin (loss) is calculated as revenues less direct operating expenses, including depreciation and amortization expense.

The following table presents our average utilization rates and rigs available for service for the nine months ended September 30, 2016 and 2015, respectively:

	Nine Months Ended September 30,
	2016		2015
U.S. (Lower 48) Drilling
Rigs available for service (1)	13.0		13.0
Utilization rate of rigs available for service (2)	6	%	17	%
International & Alaska Drilling
Eastern Hemisphere
Rigs available for service (1)	13.0		13.0
Utilization rate of rigs available for service (2)	41	%	70	%
Latin America Region
Rigs available for service (1)	7.0		9.0
Utilization rate of rigs available for service (2)	26	%	44	%
Alaska
Rigs available for service (1)	2.0		2.0
Utilization rate of rigs available for service (2)	100	%	100	%
Total International & Alaska Drilling
Rigs available for service (1)	22.0		24.0
Utilization rate of rigs available for service (2)	42	%	63	%

(1) The number of rigs available for service is determined by calculating the number of days each rig was in our fleet and was under contract or available for contract. For example, a rig under contract or available for contract for six months of a year is 0.5 rigs available for service during such year. Our method of computation of rigs available for service may not be comparable to other similarly titled measures of other companies.

(2) Rig utilization rates are based on a weighted average basis assuming total days availability for all rigs available for service. Rigs acquired or disposed of are treated as added to or removed from the rig fleet as of the date of acquisition or disposal. Rigs that are in operation or fully or partially staffed and on a revenue-producing standby status are considered to be utilized. Rigs under contract that generate revenues during moves between locations or during mobilization or demobilization are also considered to be utilized. Our method of computation of rig utilization may not be comparable to other similarly titled measures of other companies.

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Drilling Services Business

U.S. (Lower 48) Drilling

U.S. (Lower 48) Drilling segment revenues decreased $22.3 million, or 82.9 percent, to $4.6 million for the nine months ended September 30, 2016 compared with revenues of $26.9 million for the nine months ended September 30, 2015. The decrease was primarily due to lower utilization driven by substantial reductions in drilling activity by operators in the inland waters of the GOM resulting from lower oil prices. Utilization declined to 6.0 percent for the nine months ended September 30, 2016 from 17.0 percent for the nine months ended September 30, 2015, resulting in a $12.3 million decrease in revenues. The remainder of the decrease in revenues was primarily due to a decrease of $6.4 million from our O&M contract supporting three platform operations located offshore California that ended during the 2015 fourth quarter, as well as $3.0 million resulting from reduced dayrates and reimbursable revenues.

U.S. (Lower 48) Drilling segment operating gross margin excluding depreciation and amortization decreased $7.2 million to a loss of $10.9 million for the nine months ended September 30, 2016 compared with a loss of $3.7 million for the nine months ended September 30, 2015. The decrease was primarily due to the decline in utilization and reduced dayrates discussed above.

International & Alaska Drilling

International & Alaska Drilling segment revenues decreased $113.7 million, or 33.5 percent, to $225.9 million for the nine months ended September 30, 2016 compared with $339.6 million for the nine months ended September 30, 2015.

The decrease in revenues was primarily due to the following:

• a decrease of $47.3 resulting from decreased utilization for Company-owned rigs driven by the decline in oil prices resulting in reduced customer activity. Utilization for the segment decreased to 42.0 percent for the nine months ended September 30, 2016 from 63.0 percent for the nine months ended September 30, 2015;

• a decrease of $36.0 million driven by a decline in revenues per day resulting from certain Company-owned and customer-owned rigs shifting to standby mode during 2016 compared with operating mode during 2015, as well as a reduction in average dayrates due to pricing pressures from customers resulting from the decline in oil prices;

• a decrease of $13.3 million in revenues earned from mobilization and demobilization activities;

• a decrease in reimbursable revenues of $11.5 million, which decreased revenues but had a minimal impact on operating margins; and

• a decrease of $4.1 million in revenues related to our project services activities.

International & Alaska Drilling segment operating gross margin excluding depreciation and amortization decreased $36.8 million, or 42.3 percent, to $50.3 million for the nine months ended September 30, 2016 compared with $87.1 million for the nine months ended September 30, 2015. The decrease in operating gross margin excluding depreciation and amortization was primarily due to the impact of reduced utilization and reduced revenues per day discussed above.

Rental Tools Services Business

U.S. Rental Tools

U.S. Rental Tools segment revenues decreased $57.7 million, or 51.0 percent, to $55.5 million for the nine months ended September 30, 2016 compared with $113.2 million for the nine months ended September 30, 2015. The decrease was primarily driven by continued reduction in customer activity and pricing pressures resulting from lower oil prices impacting both U.S. land and offshore GOM rentals.

U.S. Rental Tools segment operating gross margin excluding depreciation and amortization decreased $34.3 million, or 66.3 percent, to $17.4 million in the nine months ended September 30, 2016 compared with $51.7 million for the nine months ended September 30, 2015. The decrease was due to the declines in oil prices and customer activity discussed above, partially offset by lower operating costs resulting from cost reduction efforts.

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International Rental Tools

International Rental Tools segment revenues decreased $36.7 million, or 43.8 percent, to $47.1 million for the nine months ended September 30, 2016 compared with $83.8 million for the nine months ended September 30, 2015. The decrease was primarily attributable to the continued reduction in customer activity and price erosion resulting from lower oil prices across most of our markets, with the largest declines in our U.K. North Sea, Asia Pacific and Latin America operations.

International Rental Tools segment operating gross margin excluding depreciation and amortization decreased $22.4 million, or 134.9 percent, to a loss of $5.8 million for the nine months ended September 30, 2016 compared with gross margin of $16.6 million for the nine months ended September 30, 2015. The decrease was due to the declines in oil prices and customer activity discussed above, partially offset by lower operating costs resulting from cost reduction efforts.

Other Financial Data

General and administrative expense

General and administrative expense decreased $4.0 million to $25.2 million for the nine months ended September 30, 2016, compared with $29.2 million for the nine months ended September 30, 2015. General and administrative expense for the nine months ended September 30, 2016 benefited from reduced personnel costs resulting from cost savings initiatives. In addition, during the nine months ended September 30, 2015 we incurred increased expenses as we implemented the second phase of our new enterprise resource planning system in 2015.

Provision for reduction in carrying value of certain assets

There was no provision for reduction in carrying value of certain assets recorded during the nine months ended September 30, 2016 compared with a $3.2 million provision for reduction in carrying value recorded during the nine months ended September 30, 2015. During the nine months ended September 30, 2015, we recorded a $3.2 million provision related to certain international rental tools and drilling rigs as management concluded that due to changing market conditions the rental tools and rigs were no longer marketable and the carrying value of the rental tools and rigs was no longer recoverable.

Gain (loss) on disposition of assets

Net losses recognized on asset dispositions were $0.2 million during the nine months ended September 30, 2016, compared with net gains of $2.7 million during the nine months ended September 30, 2015. Activity in both periods included the results of asset sales; however, the net gains for the nine months ended September 30, 2015 were primarily due to an insurance settlement received during the period related to previously realized asset losses. Additionally, we periodically sell equipment deemed to be excess, obsolete, or not currently required for operations.

Interest income and expense

Interest expense increased $1.0 million to $34.8 million for the nine months ended September 30, 2016 compared with $33.8 million for the nine months ended September 30, 2015. The increase in interest expense was primarily related to a write off of $1.1 million of debt issuance costs during the second quarter of 2016 in conjunction with the execution of the Third Amendment to the 2015 Secured Credit Agreement on May 27, 2016, which resulted in the reduction of total lender commitments under our Revolver by 50 percent. Interest income during each of the nine months ended September 30, 2016 and 2015 was nominal.

Other income and expense

Other income for the nine months ended September 30, 2016 was $1.8 million compared with other expense for the nine months ended September 30, 2015 of $3.6 million. Other income for the nine months ended September 30, 2016 was primarily attributable to a reclassification of $1.9 million of realized foreign currency translation gains from accumulated other comprehensive income and the settlement of certain legal claims, resulting in other income of $0.6 million; partially offset by foreign currency fluctuations. Other expense for the nine months ended September 30, 2015 was primarily driven by losses related to foreign currency fluctuations and a loss on divestiture of our controlling interest in a consolidated joint venture.

Income tax expense (benefit)

During the nine months ended September 30, 2016, we had income tax expense of $67.9 million compared with income tax expense of $24.8 million during the nine months ended September 30, 2015.  Despite the pre-tax loss for the nine months ended September 30, 2016, we recognized income tax expense as a result of recording a valuation allowance in the first quarter of $73.1 million against our U.S. domestic deferred tax assets, which primarily consist of U.S. federal net operating losses.  The

39

income tax expense for the nine months ended September 30, 2015 was a result of recording a valuation allowance of $36.6 million, primarily on U.S. foreign tax credits and certain foreign net operating losses.

Backlog

Backlog is our estimate of the dollar amount of revenues we expect to realize in the future as a result of executing awarded contracts. The Company’s backlog of firm orders was approximately $421 million at September 30, 2016 and $378 million at September 30, 2015 and is primarily attributable to the International & Alaska segment of our Drilling Services business. We estimate that, as of September 30, 2016, 11 percent of our backlog will be recognized as revenues within the fiscal year.

The amount of actual revenues earned and the actual periods during which revenues are earned could be different from amounts disclosed in our backlog calculations due to a lack of predictability of various factors, including unscheduled repairs, maintenance requirements, weather delays, contract terminations or renegotiations, new contracts and other factors. See “Our backlog of contracted revenue may not be fully realized and may reduce significantly in the future, which may have a material adverse effect on our financial position, results of operations or cash flows” in Item 1A. Risk Factors of our 2015 Form 10-K. 

LIQUIDITY AND CAPITAL RESOURCES

We periodically evaluate our liquidity requirements, capital needs and availability of resources in view of expansion plans, debt service requirements, and other operational cash needs. To meet our short- and long-term liquidity requirements, including payment of operating expenses and repaying debt, we rely primarily on cash from operations. We also have access to cash through the Revolver, subject to our compliance with the covenants contained in the 2015 Secured Credit Agreement. We expect that these sources of liquidity will be sufficient to provide us the ability to fund our operations, provide the working capital necessary to support our strategy, and fund planned capital expenditures. When determined appropriate we may seek to raise additional capital in the future. We do not pay dividends to our shareholders.

Liquidity

The following table provides a summary of our total liquidity:

	September 30, 2016
Dollars in thousands
Cash and cash equivalents on hand (1)	$	103,613
Availability under Revolver (2)	90,417
Total liquidity	$	194,030

(1) As of September 30, 2016, approximately $34.8 million of the $103.6 million of cash and equivalents was held by our foreign subsidiaries.

(2) Availability under the Revolver included $100 million undrawn portion of our Revolver less $9.6 million of letters of credit outstanding. In order to access the Revolver, we must be in compliance with the covenants contained in the 2015 Secured Credit Agreement.

The earnings of foreign subsidiaries as of September 30, 2016 were reinvested to fund our international operations.  If in the future we decide to repatriate earnings to the U.S., the Company may be required to pay taxes on these amounts based on applicable U.S. tax law, which would reduce the liquidity of the Company at that time.

We do not have any unconsolidated special-purpose entities, off-balance sheet financing arrangements or guarantees of third-party financial obligations. As of September 30, 2016, we have no energy, commodity, or foreign currency derivative contracts.

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Cash Flow Activity

As of September 30, 2016, we had cash and cash equivalents of $103.6 million, a decrease of $30.7 million from cash and cash equivalents of $134.3 million at December 31, 2015. The following table provides a summary of our cash flow activity:

	Nine Months Ended September 30, 2016
Dollars in thousands	2016			2015
Operating activities	$	(857	)	$	108,852
Investing activities	(18,698		)	(79,669		)
Financing activities	(11,126		)	(32,988		)
Net change in cash and cash equivalents	$	(30,681	)	$	(3,805	)

Operating Activities

Cash flows from operating activities were a use of $0.9 million for the nine months ended September 30, 2016 compared with a source of $108.9 million for the nine months ended September 30, 2015. Cash flows from operating activities in each period were largely impacted by our earnings and changes in working capital. Changes in working capital were a source of cash of $15.5 million for the nine months ended September 30, 2016 compared with a source of cash of $29.6 million for the nine months ended September 30, 2015. In addition to the impact of earnings and working capital changes cash flows from operating activities in each period were impacted by non-cash charges such as depreciation expense, gains on asset sales, deferred tax benefit, stock compensation expense, debt modification and amortization of debt issuance costs.

Over the past few years we have reinvested a substantial portion of our operating cash flows to enhance our fleet of drilling rigs and our rental tools equipment inventory. It is our long term intention to utilize our operating cash flows to fund maintenance and growth of our rental tool assets and drilling rigs; however, given the decline in demand in the current oil and natural gas services market, our short-term focus is to preserve liquidity by managing our costs and capital expenditures.

Investing Activities

Cash flows from investing activities were a use of $18.7 million for the nine months ended September 30, 2016 compared with a use of $79.7 million for the nine months ended September 30, 2015. Our primary use of cash during the nine months ended September 30, 2016 and 2015 was $21.0 million and $72.5 million, respectively, for capital expenditures. Capital expenditures in each period were primarily for tubular and other products for our Rental Tools Services business and rig-related maintenance. During the nine months ended September 30, 2015 we had a use of cash of $10.4 million, net of cash acquired, in connection with the 2M-Tek Acquisition.

Financing Activities

Cash flows from financing activities were a use of $11.1 million for the nine months ended September 30, 2016, primarily due to the payments of the contingent consideration related to the 2M-Tek Acquisition of $6.0 million. The payments were made upon the achievement of certain milestones during the first and second quarters of 2016. In addition, during the nine months ended September 30, 2016, we had a use of cash of $3.4 million in connection with the final payment of the purchase price for the remaining noncontrolling interest of ITS Arabia Limited. Cash flows from financing activities were a use of $33.0 million for the 2015 comparable period, primarily driven by the repayment of the $30.0 million balance on a term loan in the first quarter of 2015.

Long-Term Debt Summary

Our principal amount of long-term debt, including current portion, was $575.9 million as of September 30, 2016 which consisted of:

•$360.0 million aggregate principal amount of 6.75% Notes; and

•$225.0 million aggregate principal amount of 7.50% Notes; less

•$9.1 million of unamortized debt issuance costs

6.75% Senior Notes, due July 2022

On January 22, 2014, we issued $360.0 million aggregate principal amount of 6.75% Senior Notes due 2022 (6.75% Notes) pursuant to an Indenture between the Company and The Bank of New York Mellon Trust Company, N.A., as trustee. Net proceeds from the 6.75% Notes offering plus a $40.0 million term loan draw under the Amended and Restated Senior Secured

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Credit Agreement (2012 Secured Credit Agreement) and cash on hand were utilized to purchase $416.2 million aggregate principal amount of our outstanding 9.125% Senior Notes due 2018 pursuant to a tender and consent solicitation offer commenced on January 7, 2014.

The 6.75% Notes are general unsecured obligations of the Company and rank equal in right of payment with all of our existing and future senior unsecured indebtedness. The 6.75% Notes are jointly and severally guaranteed by all of our subsidiaries that guarantee indebtedness under the Second Amended and Restated Senior Secured Credit Agreement, as amended from time-to-time (2015 Secured Credit Agreement) and our 7.50% Senior Notes due 2020 (7.50% Notes, and collectively with the 6.75% Notes, the Senior Notes). Interest on the 6.75% Notes is payable on January 15 and July 15 of each year, beginning July 15, 2014. Debt issuance costs related to the 6.75% Notes of approximately $7.6 million ($5.7 million net of amortization as of September 30, 2016) are being amortized over the term of the notes using the effective interest rate method.

At any time prior to January 15, 2017, we may redeem up to 35 percent of the aggregate principal amount of the 6.75% Notes at a redemption price of 106.75 percent of the principal amount, plus accrued and unpaid interest to the redemption date, with the net cash proceeds of certain equity offerings by us. To date we have not made any redemptions. On and after January 15, 2018, we may redeem all or a part of the 6.75% Notes upon appropriate notice, at a redemption price of 103.375 percent of the principal amount, and at redemption prices decreasing each year thereafter to par beginning January 15, 2020. If we experience certain changes in control, we must offer to repurchase the 6.75% Notes at 101.0 percent of the aggregate principal amount, plus accrued and unpaid interest and additional interest, if any, to the date of repurchase.

The Indenture restricts our ability and the ability of certain subsidiaries to: (i) sell assets, (ii) pay dividends or make other distributions on capital stock or redeem or repurchase capital stock or subordinated indebtedness, (iii) make investments, (iv) incur or guarantee additional indebtedness, (v) create or incur liens, (vi) enter into sale and leaseback transactions, (vii) incur dividend or other payment restrictions affecting subsidiaries, (viii) merge or consolidate with other entities, (ix) enter into transactions with affiliates, and (x) engage in certain business activities. Additionally, the Indenture contains certain restrictive covenants designating certain events as Events of Default. These covenants are subject to a number of important exceptions and qualifications.

7.50% Senior Notes, due August 2020

On July 30, 2013, we issued $225.0 million aggregate principal amount of the 7.50% Notes pursuant to an Indenture between the Company and The Bank of New York Mellon Trust Company, N.A., as trustee. Net proceeds from the 7.50% Notes offering were primarily used to repay the $125.0 million aggregate principal amount of a term loan used to initially finance the ITS Acquisition, to repay $45.0 million of term loan borrowings under the 2012 Secured Credit Agreement, and for general corporate purposes.

The 7.50% Notes are general unsecured obligations of the Company and rank equal in right of payment with all of our existing and future senior unsecured indebtedness. The 7.50% Notes are jointly and severally guaranteed by all of our subsidiaries that guarantee indebtedness under the 2015 Secured Credit Agreement and the 6.75% Notes. Interest on the 7.50% Notes is payable on February 1 and August 1 of each year, beginning February 1, 2014. Debt issuance costs related to the 7.50% Notes of approximately $5.6 million ($3.4 million, net of amortization as of September 30, 2016) are being amortized over the term of the notes using the effective interest rate method.

On and after August 1, 2016, we may redeem all or a part of the 7.50% Notes upon appropriate notice, at a redemption price of 103.750 percent of the principal amount, and at redemption prices decreasing each year thereafter to par beginning August 1, 2018. To date we have not made any redemptions. If we experience certain changes in control, we must offer to repurchase the 7.50% Notes at 101.0 percent of the aggregate principal amount, plus accrued and unpaid interest and additional interest, if any, to the date of repurchase.

The Indenture restricts our ability and the ability of certain subsidiaries to: (i) sell assets, (ii) pay dividends or make other distributions on capital stock or redeem or repurchase capital stock or subordinated indebtedness, (iii) make investments, (iv) incur or guarantee additional indebtedness, (v) create or incur liens, (vi) enter into sale and leaseback transactions, (vii) incur dividend or other payment restrictions affecting subsidiaries, (viii) merge or consolidate with other entities, (ix) enter into transactions with affiliates, and (x) engage in certain business activities. Additionally, the Indenture contains certain restrictive covenants designating certain events as Events of Default. These covenants are subject to a number of important exceptions and qualifications.

2015 Secured Credit Agreement

On January 26, 2015 we entered into the 2015 Secured Credit Agreement, which amended and restated the 2012 Secured Credit Agreement. The 2015 Secured Credit Agreement was originally comprised of a $200.0 million revolving credit facility (Revolver) set to mature on January 26, 2020. On June 1, 2015, we executed the first amendment to the 2015 Secured Credit Agreement in order to amend certain provisions regarding the definition of “Change of Control.” On September 29, 2015, we executed the second amendment to the 2015 Secured Credit Agreement to, among other things, (a) amend certain covenant ratios; (b) increase the Applicable Rate for certain higher levels of consolidated leverage to a maximum of 4.00 percent per annum for

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Eurodollar Rate loans and to 3.00 percent per annum for Base Rate loans; (c) permit multi-year letters of credit up to an aggregate amount of $5.0 million; (d) limit payment prior to September 30, 2017 of certain restricted payments and certain prepayments of unsecured senior notes and other specified forms of indebtedness; and (e) remove the option of the Company, subject to the consent of the lenders, to increase the Credit Agreement up to an additional $75 million. On May 27, 2016, we executed the third amendment to the 2015 Secured Credit Agreement (the Third Amendment), which reduced availability under the Revolver from $200 million to $100 million. Additionally, among other things, the Third Amendment: (a) eliminated the Leverage Ratio covenant until the fourth quarter of 2018 when the covenant is reinstated with the ratio established at 4.25:1.00, and remains at 4.25:1.00 thereafter; (b) eliminated the Consolidated Interest Coverage Ratio covenant until the fourth quarter of 2017 when the covenant is reinstated with the ratio established at 1.00:1.00 and increases by 0.25 each subsequent quarter until reaching 2.00:1.00 in the fourth quarter of 2018, and remains at 2.00:1.00 thereafter; (c) immediately increased the maximum permitted Senior Secured Leverage Ratio from 1.50:1.00 to 2.80:1.00 until it decreases to 2.20:1.00 in the second quarter of 2017, to 1.75:1.00 in the third quarter of 2017, and to 1.50:1.00 in the fourth quarter of 2017 and remains at 1.50:1.00 thereafter; (d) immediately decreased the minimum permitted Asset Coverage Ratio from 1.25:1.00 to 1.10:1.00 until it increases to 1.25: 1.00 in the fourth quarter of 2017 and remains at 1.25:1.00 thereafter; (e) requires that, at any time our Consolidated Cash Balance in U.S. bank accounts is over $50 million, we repay borrowings under the 2015 Secured Credit Agreement until our Consolidated Cash balance is no more than $50 million or all borrowings have been repaid, and (f) allows up to $75 million of Junior Lien Debt.

At the time the Third Amendment was executed, the remaining debt issuance costs for the 2015 Secured Credit Agreement totaled approximately $2.2 million. Since the Revolver was reduced by 50 percent, we wrote off approximately $1.1 million in May 2016. We incurred debt issuance costs relating to the Third Amendment of approximately $0.3 million, bringing total debt issuance costs to $1.4 million ($1.3 million, net of amortization as of September 30, 2016) which are being amortized through January 2020, or the term of the Third Amendment, on a straight line basis.

Our obligations under the 2015 Secured Credit Agreement are guaranteed by substantially all of our direct and indirect domestic subsidiaries, other than immaterial subsidiaries and subsidiaries generating revenues primarily outside the United States, each of which has executed guaranty agreements, and are secured by first priority liens on our accounts receivable, specified rigs including barge rigs in the GOM and land rigs in Alaska, certain U.S.-based rental equipment of the Company and its subsidiary guarantors and the equity interests of certain of the Company’s subsidiaries. The 2015 Secured Credit Agreement contains customary affirmative and negative covenants, such as limitations on indebtedness, liens, restrictions on entry into certain affiliate transactions and payments (including payment of dividends) and maintenance of certain ratios and coverage tests. We were in compliance with all covenants contained in the 2015 Secured Credit Agreement as of September 30, 2016.

Our Revolver is available for general corporate purposes and to support letters of credit. Interest on Revolver loans accrues at a Base Rate plus an Applicable Rate or LIBOR plus an Applicable Rate. Revolving loans are available subject to a quarterly asset coverage ratio calculation based on the Orderly Liquidation Value of certain specified rigs including barge rigs in the GOM and land rigs in Alaska, and certain U.S.-based rental equipment of the Company and its subsidiary guarantors and a percentage of eligible domestic accounts receivable. The $30.0 million draw outstanding at the closing of the 2015 Secured Credit Agreement was repaid in full during the first quarter of 2015 with cash on hand. Letters of credit outstanding against the Revolver as of September 30, 2016 totaled $9.6 million. There were no amounts drawn on the Revolver as of September 30, 2016.

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DISCLOSURE NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Form 10-Q contains statements that are “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the Exchange Act). All statements contained in this Form 10-Q, other than statements of historical facts, are forward-looking statements for purposes of these provisions, including any statements regarding:

•stability or volatility of prices and demand for oil and natural gas;

•levels of oil and natural gas exploration and production activities;

•demand for contract drilling and drilling-related services and demand for rental tools and related services;

•our future operating results and profitability;

•our future rig utilization, dayrates and rental tools activity;

• entering into new, or extending existing, drilling or rental contracts and our expectations concerning when operations will commence under such contracts;

•entry into new markets or potential exit from existing markets;

•growth through acquisitions of companies or assets;

•organic growth of our operations;

• construction or upgrades of rigs or drilling services equipment and expectations regarding when such rigs or equipment will commence operations;

• capital expenditures for acquisition of rental tools or rigs, construction of new rigs or drilling services equipment or major upgrades to existing rigs or equipment;

•entering into joint venture agreements;

•our future liquidity;

•sale or potential sale of assets or references to assets held for sale;

•availability and sources of funds to refinance our debt and expectations of when debt will be reduced;

•the outcome of pending or future legal proceedings, investigations, tax assessments and other claims;

•the availability of insurance coverage for pending or future claims;

•the enforceability of contractual indemnification in relation to pending or future claims; and

•compliance with covenants under our debt agreements.

In some cases, you can identify these statements by forward-looking words such as “anticipate,” “believe,” “could,” “estimate,” “expect,” “intend,” “outlook,” “may,” “should,” “will” and “would” or similar words. Forward-looking statements are based on certain assumptions and analyses we make in light of our experience and perception of historical trends, current conditions, expected future developments and other factors we believe are relevant. Although we believe that our assumptions are reasonable based on information currently available, those assumptions are subject to significant risks and uncertainties, many of which are outside of our control. The following factors, as well as any other cautionary language included in this Form 10-Q, provide examples of risks, uncertainties and events that may cause our actual results to differ materially from the expectations we describe in our forward-looking statements:

• fluctuations in the market prices of oil and natural gas, including the inability or unwillingness of our customers to fund drilling programs in low price cycles;

• worldwide economic and business conditions that adversely affect market conditions and/or the cost of doing business, including potential currency devaluations or collapses;

•our inability to access the credit markets;

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• U.S. credit market volatility resulting from a restrictive regulatory environment imposed upon lenders due to their over exposure to the energy industry;

•the U.S. economy and the demand for oil and natural gas;

•low oil and natural gas prices that could adversely affect our drilling services and rental tools services businesses;

•worldwide demand for oil;

• imposition of trade restrictions, including additional economic sanctions and export/re export controls affecting our business operations in Russia;

•unanticipated operating hazards and uninsured risks;

•political instability, terrorism or war;

• governmental regulations, including changes in accounting rules or tax laws that adversely affect the cost of doing business or our ability to remit funds to the U.S.;

•changes in the tax laws that would allow double taxation on foreign sourced income;

•the outcome of investigations into possible violations of laws;

•adverse environmental events;

•adverse weather conditions;

•global health concerns;

•changes in the concentration of customer and supplier relationships;

•ability of our customers and suppliers to obtain financing for their operations;

•ability of our customers to fund drilling plans;

•unexpected cost increases for new construction and upgrade and refurbishment projects;

•delays in obtaining components for capital projects and in ongoing operational maintenance and equipment certifications;

•shortages of skilled labor;

•unanticipated cancellation of contracts by customers or operators;

•breakdown of equipment;

•other operational problems including delays in start-up or commissioning of rigs;

•changes in competition;

•any failure to realize expected benefits from acquisitions;

•the effect of litigation and contingencies; and

• other similar factors, some of which are discussed in documents referred to or incorporated by reference into this Form 10-Q and our other reports and filings with the Securities and Exchange Commission (SEC).

Each forward-looking statement speaks only as of the date of this Form 10-Q, and we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. You should be aware that the occurrence of the events described in these risk factors and elsewhere in this Form 10-Q could have a material adverse effect on our business, results of operations, financial condition and cash flows.

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Item 3. Quantitative and Qualitative Disclosures about Market Risk

There has been no material change in the market risk faced by us from that reported in our 2015 Form 10-K. For more information on market risk, see Part II, Item 7A in our 2015 Form 10-K.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

In accordance with Rules 13a-15 and 15d-15 under the Exchange Act, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective, as of September 30, 2016, to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and accumulated and communicated to our management, including our Chief Executive Officer and our Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

Changes in Internal Controls Over Financial Reporting

There have been no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during our most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings

For information regarding legal proceedings, see Note 11, “Commitments and Contingencies,” in Item 1 of Part I of this quarterly report on Form 10-Q, which information is incorporated into this item by reference.

Item 1A. Risk Factors

There have been no material changes from the risk factors disclosed in Item 1A. Risk Factors of our 2015 Form 10-K.

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

The Company currently has no active share repurchase programs.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

None.

Item 5. Other Information

None.

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Item 6. Exhibits

The following exhibits are filed or furnished as a part of this report:

Exhibit Number		Description
3.1	—	Restated Certificate of Incorporation of Parker Drilling Company, as amended on May 16, 2007 (incorporated by reference to Exhibit 3.1 to the Company’s Quarterly Report on Form 10-Q filed on November 9, 2007).
3.2	—	By-laws of Parker Drilling Company, as amended and restated as of July 31, 2014 (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on August 1, 2014).
12.1	—	Computation of Ratio of Earnings to Fixed Charges.
31.1	—	Gary G. Rich, Chairman, President and Chief Executive Officer, Rule 13a-14(a)/15d-14(a) Certification.
31.2	—	Christopher T. Weber, Senior Vice President and Chief Financial Officer, Rule 13a-14(a)/15d-14(a) Certification.
32.1	—	Gary G. Rich, Chairman, President and Chief Executive Officer, Section 1350 Certification.
32.2	—	Christopher T. Weber, Senior Vice President and Chief Financial Officer, Section 1350 Certification.
101.INS	—	XBRL Instance Document.
101.SCH	—	XBRL Taxonomy Schema Document.
101.CAL	—	XBRL Calculation Linkbase Document.
101.LAB	—	XBRL Label Linkbase Document.
101.PRE	—	XBRL Presentation Linkbase Document.
101.DEF	—	XBRL Definition Linkbase Document.

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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.

		PARKER DRILLING COMPANY
Date:	October 31, 2016	By:	/s/ Gary G. Rich
			Gary G. Rich Chairman, President and Chief Executive Officer
		By:	/s/ Christopher T. Weber
			Christopher T. Weber Senior Vice President and Chief Financial Officer

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INDEX TO EXHIBITS

Exhibit Number		Description
3.1	—	Restated Certificate of Incorporation of Parker Drilling Company, as amended on May 16, 2007 (incorporated by reference to Exhibit 3.1 to the Company’s Quarterly Report on Form 10-Q filed on November 9, 2007).
3.2	—	By-laws of Parker Drilling Company, as amended and restated as of July 31, 2014 (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on August 1, 2014).
12.1	—	Computation of Ratio of Earnings to Fixed Charges.
31.1	—	Gary G. Rich, Chairman, President and Chief Executive Officer, Rule 13a-14(a)/15d-14(a) Certification.
31.2	—	Christopher T. Weber, Senior Vice President and Chief Financial Officer, Rule 13a-14(a)/15d-14(a) Certification.
32.1	—	Gary G. Rich, Chairman, President and Chief Executive Officer, Section 1350 Certification.
32.2	—	Christopher T. Weber, Senior Vice President and Chief Financial Officer, Section 1350 Certification.
101.INS	—	XBRL Instance Document.
101.SCH	—	XBRL Taxonomy Schema Document.
101.CAL	—	XBRL Calculation Linkbase Document.
101.LAB	—	XBRL Label Linkbase Document.
101.PRE	—	XBRL Presentation Linkbase Document.
101.DEF	—	XBRL Definition Linkbase Document.

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