Parker Drilling (PKDC) 10-Q 2016 Q1 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 March 31, 2016

OR

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

For the transition period from                      to                         

Commission File Number 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 May 2, 2016 there were 123,982,716 common shares outstanding.    

TABLE OF CONTENTS

	Page
Part I. Financial Information
Item 1. Financial Statements	3
Consolidated Condensed Balance Sheets as at March 31, 2016 (Unaudited) and December 31, 2015	3
Consolidated Condensed Statements of Operations (Unaudited) for the Three Months Ended March 31, 2016 and 2015	4
Consolidated Condensed Statements of Comprehensive Income (Loss) (Unaudited) for the Three Months Ended March 31, 2016 and 2015	5
Consolidated Condensed Statements of Cash Flows (Unaudited) for the Three Months Ended March 31, 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	27
Item 3. Quantitative and Qualitative Disclosures about Market Risk	37
Item 4. Controls and Procedures	37
Part II. Other Information
Item 1. Legal Proceedings	38
Item 1A. Risk Factors	38
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	38
Item 3. Defaults Upon Senior Securities	38
Item 4. Mine Safety Disclosures	38
Item 5. Other Information	38
Item 6. Exhibits	39
Signatures	40

2

PART I.FINANCIAL INFORMATION

Item 1. Financial Statements

PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATED CONDENSED BALANCE SHEETS

(Dollars in Thousands)

	March 31, 2016			December 31, 2015
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	108,427		$	134,294
Accounts and Notes Receivable, net of allowance for bad debts of $8,250 at March 31, 2016 and $8,694 at December 31, 2015.	175,382			175,105
Rig materials and supplies	36,508			34,937
Other current assets	24,438			22,405
Total current assets	344,755			366,741
Property, plant and equipment, net of accumulated depreciation of $1,329,305 at March 31, 2016 and $1,302,380 at December 31, 2015.	776,912			805,841
Goodwill (Note 3)	6,708			6,708
Intangible assets, net (Note 3)	12,220			13,377
Deferred income taxes	78,992			139,282
Other noncurrent assets	35,062			34,753
Total assets	$	1,254,649		$	1,366,702
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities	114,993			129,703
Accrued income taxes	5,980			6,418
Total current liabilities	120,973			136,121
Long-term debt, net of unamortized debt issuance costs of $9,829 at March 31, 2016 and $10,202 at December 31, 2015.	575,171			574,798
Other long-term liabilities	13,755			18,617
Long-term deferred tax liability	71,898			68,654
Commitments and contingencies (Note 12)
Stockholders’ equity:
Common stock	20,604			20,518
Capital in excess of par value	670,245			669,120
Accumulated deficit	(215,073		)	(119,238		)
Accumulated other comprehensive (loss)	(2,924		)	(1,888		)
Total stockholders’ equity	472,852			568,512
Total liabilities and stockholders’ equity	$	1,254,649		$	1,366,702

See accompanying notes to the unaudited consolidated condensed financial statements.

3

PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENTS OF OPERATIONS

(Dollars in Thousands, Except Per Share Data)

(Unaudited)

	Three Months Ended March 31,
	2016			2015
Revenues	$	130,503		$	204,076
Expenses:
Operating expenses	108,117			139,270
Depreciation and amortization	35,814			40,539
	143,931			179,809
Total operating gross margin	(13,428		)	24,267
General and administration expense	(9,781		)	(10,837		)
Gain (loss) on disposition of assets, net	(60		)	2,441
Total operating income (loss)	(23,269		)	15,871
Other income and (expense):
Interest expense	(11,562		)	(11,078		)
Interest income	7			183
Other	2,485			(1,380		)
Total other expense	(9,070		)	(12,275		)
Income (loss) before income taxes	(32,339		)	3,596
Income tax expense (benefit)	63,496			(182		)
Net income (loss)	(95,835		)	3,778
Less: Net income attributable to noncontrolling interest	—			556
Net income (loss) attributable to controlling interest	$	(95,835	)	$	3,222
Basic earnings (loss) per share	$	(0.78	)	$	0.03
Diluted earnings (loss) per share	$	(0.78	)	$	0.03
Number of common shares used in computing earnings per share:
Basic	123,090,238			121,887,072
Diluted	123,090,238			123,708,623

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 March 31, 2016
	2016			2015
Comprehensive income:
Net income (loss)	$	(95,835	)	$	3,778
Other comprehensive income (loss), net of tax:
Currency translation difference on related borrowings	502			(1,670		)
Currency translation difference on foreign currency net investments	(1,538		)	(849		)
Total other comprehensive income (loss), net of tax:	(1,036		)	(2,519		)
Comprehensive income (loss)	(96,871		)	1,259
Comprehensive (loss) attributable to noncontrolling interest	—			(394		)
Comprehensive income (loss) attributable to controlling interest	$	(96,871	)	$	865

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)

	Three Months Ended March 31,
	2016			2015
Cash flows from operating activities:
Net income (loss)	$	(95,835	)	$	3,778
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization	35,814			40,539
Accretion of contingent consideration	419			—
(Gain) loss on disposition of assets	60			(2,441		)
Deferred income tax expense (benefit)	63,411			(6,304		)
Expenses not requiring cash	(426		)	1,737
Change in assets and liabilities:
Accounts and notes receivable	(381		)	(6,650		)
Other assets	(304		)	(20,087		)
Accounts payable and accrued liabilities	(14,437		)	54,045
Accrued income taxes	(3,600		)	2,614
Net cash provided by (used in) operating activities	(15,279		)	67,231
Cash flows from investing activities:
Capital expenditures	(7,889		)	(33,455		)
Proceeds from the sale of assets	54			246
Proceeds from insurance settlements	—			2,500
Net cash (used in) investing activities	(7,835		)	(30,709		)
Cash flows from financing activities:
Repayments of long-term debt	—			(30,000		)
Payments of debt issuance costs	—			(1,359		)
Payments of contingent consideration	(2,000		)	—
Excess tax (expense) from stock based compensation	(753		)	(420		)
Net cash (used in) financing activities	(2,753		)	(31,779		)
Net increase (decrease) in cash and cash equivalents	(25,867		)	4,743
Cash and cash equivalents, beginning of year	134,294			108,456
Cash and cash equivalents, end of period	$	108,427		$	113,199
Supplemental cash flow information:
Interest paid	$	20,588		$	20,805
Income taxes paid	$	4,734		$	4,601

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

In the opinion of the management of Parker Drilling Company (Parker Drilling or the Company), the accompanying unaudited consolidated condensed financial statements reflect all adjustments normally recurring which we believe are necessary for a fair presentation of: (1) Parker Drilling’s financial position as of March 31, 2016 and December 31, 2015, respectively, (2) Parker Drilling’s results of operations for the three month periods ended March 31, 2016 and 2015, respectively, (3) Parker Drilling’s consolidated condensed statement of comprehensive income for the three month periods ended March 31, 2016 and 2015, respectively, and (4) Parker Drilling’s cash flows for the three month periods ended March 31, 2016 and 2015, respectively. Results for the three month period ended March 31, 2016 are not necessarily indicative of the results that will be realized for the year ending December 31, 2016. The financial statements should be read in conjunction with 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 Rental Tools Services business as one reportable segment (Rental Tools) and report our Drilling Services business as two reportable segments: (1) U.S. (Lower 48) Drilling and (2) International & Alaska Drilling.

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 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 through 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 United States (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. Generally, rental tools are used for only a portion of a well drilling program 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 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 described above, 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 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 remains payable to the seller at a later date. At the time of purchase, the carrying value of the noncontrolling interest was $3.0 million.

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.

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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 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 $19.0 million and $19.7 million for the three months ended March 31, 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 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 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/dental plans, income taxes and 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 all 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 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

8

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 39.2 percent of our revenues for the three months ended March 31, 2016. Excluding reimbursable revenues of $18.3 million, our largest customer, ENL, constituted approximately 29.5 percent of our total consolidated revenues, net of reimbursables, for the three months ended March 31, 2016. Our second largest customer, BP Exploration Alaska, Inc. (BP), constituted approximately 11.5 percent of our revenues for the three months ended March 31, 2016. Excluding reimbursable revenues of $92.0 thousand, our second largest customer constituted approximately 13.3 percent of our total consolidated revenues, net of reimbursables, for the three months ended March 31, 2016.

At March 31, 2016 and December 31, 2015, we had deposits in domestic banks in excess of federally insured limits of approximately $63.8 million and $91.3 million, respectively. In addition, we had uninsured deposits in foreign banks as of March 31, 2016 and December 31, 2015 of $46.6 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 paid at closing plus the estimated fair value of the contingent consideration of $6.8 million. We recorded the fair value of the liability for contingent consideration in “accrued liabilities” on our consolidated condensed balance sheet. 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.

We include the operations and related assets acquired and liabilities we assumed in our Rental Tools segment. This acquisition complements our existing international tubular running services (TRS) business and secures our access to a proprietary casing running tool while minimizing the total capital cost of TRS equipment going forward.

Allocation of Consideration Transferred to Net Assets Acquired

The purchase price has been allocated to the fair value of the assets acquired and liabilities assumed. The company used recognized valuation techniques to determine the fair value of the assets and liabilities. The assets acquired and liabilities assumed 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).

9

Dollars in thousands	April 17, 2015
Current Assets:
Cash and Cash Equivalents	$	17
Accounts Receivable, net	1,112
Rig materials and supplies	883
Total current assets	2,012
Property, plant and equipment	477
Goodwill	6,708
Intangible assets	13,470
Total Assets	$	22,667
Current Liabilities:
Accounts payable and accrued liabilities	$	863
Total current liabilities	863
Deferred tax liability — noncurrent	4,601
Total Liabilities	5,464
Net Assets Acquired	17,203
Total consideration transferred	$	17,203

Pro forma results of operations have not been presented because the effect of the acquisition was not material to our results of operations.

Note 3 - Goodwill and Intangible Assets

We account for all 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 events and circumstances change that indicate the carrying value of the goodwill may be impaired. During the 2016 first 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.

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 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 Rental Tools segment.

Goodwill

The change in the carrying amount of goodwill for the period ended March 31, 2016 is as follows:

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

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

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Intangible Assets

Intangible Assets consist of the following:

		Balance at March 31, 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	—			$	(1,938	)	$	9,692
Customer Relationships	3	5,400		(264		)	(5,038		)	98
Trademarks and trade names	5	4,940		(332		)	(2,178		)	2,430
Total Amortized intangible assets		$	21,970	$	(596	)	$	(9,154	)	$	12,220

(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 $1.2 million and $0.6 million for the three months ended March 31, 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	$	2,292
2017	$	2,801
2018	$	2,306
2019	$	2,306
2020	$	2,030
Beyond 2020	$	485

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

	Three Months Ended March 31, 2016
	Income (Numerator)			Shares (Denominator)	Per-Share Amount
Basic EPS	$	(95,835,000	)	123,090,238	$	(0.78	)
Effect of dilutive securities:
Restricted stock units	—			—	—
Diluted EPS	$	(95,835,000	)	123,090,238	$	(0.78	)
	Three Months Ended March 31, 2015
	Income (Numerator)			Shares (Denominator)	Per-Share Amount
Basic EPS	$	3,222,000		121,887,072	$	0.03
Effect of dilutive securities:
Restricted stock units	—			1,821,551	—
Diluted EPS	$	3,222,000		123,708,623	$	0.03

For the three months ended March 31, 2016, 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 a loss during the three month period, and therefore, inclusion of such potential common shares in the calculation would be anti-dilutive.

For the three months ended March 31, 2015, weighted-average shares outstanding used in our computation of diluted EPS includes the dilutive effect of common shares potentially issuable in connection with outstanding restricted stock unit awards.

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Note 5 - Accumulated Other Comprehensive Loss

Accumulated other comprehensive loss consisted of the following:

Dollars in thousands	Foreign Currency Items
December 31, 2015	$	(1,888	)
Current period other comprehensive (loss)	(1,036		)
March 31, 2016	$	(2,924	)

Amounts reclassified out of accumulated other comprehensive loss were $1.9 million for the three months ended March 31, 2016 and represent realized foreign currency translation gains.

Note 6 - Property, Plant and Equipment

Asset Recoverability

We review 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 through the undiscounted cash flows estimated to be generated by those assets. During the 2016 first quarter, events and circumstances indicated that carrying value of certain assets of our Rental Tools and International & Alaska Drilling segments might not be recoverable. However, our estimate of undiscounted cash flows indicated that the related carrying amounts were expected to be recovered. Should current market conditions worsen or persist for an extended period of time, it is possible that the estimate of undiscounted cash flows may change resulting in the need to write down those assets to fair value.

Note 7 - Reportable Segments

Our business is comprised of two business lines: (1) Drilling Services and (2) Rental Tools Services. We report our Rental Tools Services business as one reportable segment (Rental Tools) and report our Drilling Services business as two reportable segments: (1) U.S. (Lower 48) Drilling and (2) International & Alaska Drilling. Within the three reportable segments, we have aggregated our U.S. and international rental tools business units under Rental Tools, one business unit under U.S. (Lower 48) Drilling, and our Arctic, Eastern Hemisphere and Latin America business units under International & Alaska Drilling for a total of six business units. The Company has aggregated each of its business units in one of the three reporting segments based on the guidelines of ASC Topic 280, “Segment Reporting” (“ASC Topic 280”). We eliminate inter-segment revenues and expenses. We disclose revenues under the three reportable segments based on the similarity of the use and markets for the groups of products and services within each segment.

Drilling Services Business Line

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 through 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 hull depth 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:

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

• 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.

Our Rental Tools Services Business

Our Rental Tools segment provides 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. Generally, rental tools are used for only a portion of a well drilling program and are usually rented on a daily or monthly basis.

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

	Three Months Ended March 31,
Dollars in thousands	2016			2015
Revenues: (1)
Drilling Services:
U.S. (Lower 48) Drilling	$	2,085		$	14,097
International & Alaska Drilling	88,619			113,921
Total Drilling Services	90,704			128,018
Rental Tools	39,799			76,058
Total revenues	130,503			204,076
Operating gross margin: (2)
Drilling Services:
U.S. (Lower 48) Drilling	(8,558		)	(5,717		)
International & Alaska Drilling	5,077			17,354
Total Drilling Services	(3,481		)	11,637
Rental Tools	(9,947		)	12,630
Total operating gross margin	(13,428		)	24,267
General and administrative expense	(9,781		)	(10,837		)
Gain (loss) on disposition of assets, net	(60		)	2,441
Total operating income (loss)	(23,269		)	15,871
Interest expense	(11,562		)	(11,078		)
Interest income	7			183
Other income (loss)	2,485			(1,380		)
Income (loss) from continuing operations before income taxes	$	(32,339	)	$	3,596

(1)For the three months ended March 31, 2016, our largest customer, ENL, constituted approximately 39.2 percent of our total consolidated revenues and approximately 57.8 percent of our International & Alaska Drilling segment revenues. Excluding reimbursable revenues of $18.3 million, our largest customer, ENL, constituted approximately 29.5 percent of our total consolidated revenues, net of reimbursables, and approximately 47.2 percent of our International & Alaska Drilling segment revenues.

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Our second largest customer, BP, constituted 11.5 percent of our total consolidated revenues and approximately 16.5 percent of our International & Alaska Drilling segment revenues. Excluding reimbursable revenues of $92 thousand, our second largest customer constituted approximately 13.3 percent of our total consolidated revenues, net of reimbursables, and approximately 20.9 percent of our International & Alaska Drilling segment revenues.

For the three months ended March 31, 2015, our largest customer, ENL, constituted approximately 22.9 percent of our total consolidated revenues and approximately 41.0 percent of our International & Alaska Drilling segment revenues. Excluding reimbursable revenues of $16.0 million, our largest customer, ENL, constituted approximately 16.7 percent of our total consolidated revenues, net of reimbursables, and approximately 32.3 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 8 - 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 March 31, 2016 we had a liability for unrecognized tax benefits of $6.0 million, all of which would favorably impact our effective tax rate upon recognition, primarily related to foreign operations. At March 31, 2015, we had a liability for unrecognized tax benefits of $8.2 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 March 31, 2016 and March 31, 2015, we had approximately $1.9 million and $3.4 million, respectively, of accrued interest and penalties related to uncertain tax positions.

During the quarter ended March 31, 2016, we received assessments from a foreign tax authority related to prior year income tax returns. Previously recorded reserves were in excess of the assessed amounts and an income tax benefit of $1.4 million was recorded during the quarter. Management believes that the Company is properly reserved with respect to accounting for uncertainty in income taxes.

Note 9 - Income Tax Benefit/Expense

During the first quarter of 2016 we had income tax expense of $63.5 million compared to income tax benefit of $0.2 million during the first quarter of 2015. Despite the pre-tax operating loss for the first quarter of 2016, we recognized income tax expense as a result of recording a valuation allowance of $73.1 million against our U.S. domestic deferred tax assets, which primarily consist of U.S. federal net operating losses. We established the valuation allowance based on the weight of positive and negative evidence available, including the recent and current results of operations which reflect continued degradation in market activity and including the increased contractual uncertainty materializing during the first quarter of 2016 in the U.S. jurisdictions in which we operate. In order to determine the need for a valuation allowance, we must make estimates and assumptions. Changes in these estimates and assumptions, including changes in tax laws and other changes impacting our ability to recognize the underlying deferred tax assets, may require us to adjust the valuation allowances in the future. The income tax benefit in the first quarter of 2015 was primarily related to changes in the carrying value of certain deferred tax assets due to changes in tax law and taxing jurisdictions.

Note 10 - Long-Term Debt

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

Dollars in thousands	March 31, 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	(9,829		)	(10,202		)
Total long-term debt	$	575,171		$	574,798

6.75% Senior Notes, due July 2022

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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 (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 ($6.0 million net of amortization as of March 31, 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. 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 ($3.8 million, net of amortization as of March 31, 2016) are being amortized over the term of the notes using the effective interest rate method.

At any time prior to August 1, 2016, we may redeem up to 35 percent of the aggregate principal amount of the 7.50% Notes at a redemption price of 107.50 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. 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. 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 is comprised of a $200.0 million revolving credit facility (2015 Revolver)

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and matures on January 26, 2020. The 2012 Secured Credit Agreement consisted of an $80.0 million revolving credit facility and a $50.0 million term loan. At the closing of the 2015 Secured Credit Agreement, the outstanding balance on the term loan was $30.0 million, and we repaid this balance with a $30.0 million draw on the 2015 Revolver. On June 1, 2015, we executed the first amendment to the 2015 Secured Credit Agreement in order to amend certain provisions of the 2015 Secured Credit Agreement regarding the definition of “Change of Control.” On September 29, 2015, we executed the second amendment to the 2015 Secured Credit Agreement (the “Second Amendment”). Among other things, the Second Amendment: (a) gradually increases the permissible consolidated leverage ratio from a maximum of 4.00:1.00 to 5.75:1.00 through December 31, 2016, which thereafter gradually reduces to 4.00:1.00 by December 31, 2017; (b) reduces the consolidated interest coverage ratio from 2.50:1:00 to 2.25:1.00 for each quarter of 2016, and returning to 2.50:1.00 thereafter; (c) increases the Applicable Rate for certain higher levels of consolidated leverage to a maximum of 4.00 percent per annum for LIBOR rate loans and to 3.00 percent per annum for base rate loans; (d) allows multi-year letters of credit up to an aggregate amount of $5.0 million; (e) limits payment prior to September 30, 2017 of certain restricted payments and certain prepayments of unsecured senior notes and other specified forms of indebtedness; and (f) removes the option of the Company, subject to the consent of the lenders, to increase the Credit Agreement up to an additional $75 million. We incurred debt issuance costs related to the 2015 Secured Credit Agreement of approximately $2.0 million and had approximately $0.8 million of remaining debt issuance costs for the 2012 Secured Credit agreement. The total debt issuance costs of $2.8 million ($2.3 million, net of amortization as of March 31, 2016) are being amortized over the term of the 2015 Secured Credit Agreement 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 (including a minimum asset coverage ratio of 1.25:1.00 at each quarter end, a consolidated leverage ratio, as described above, a consolidated interest coverage ratio, as described above, and a maximum senior secured leverage ratio of 1.50:1:00 at each quarter end). We were in compliance with all such covenants as of March 31, 2016.

Our 2015 Revolver is available for general corporate purposes and to support letters of credit. Interest on 2015 Revolver loans accrues at a Base Rate plus an Applicable Rate or LIBOR plus an Applicable Rate. As a result of the Second Amendment, the Applicable Rate ranges from 2.50 percent to 4.00 percent per annum for LIBOR rate loans and from 1.50 percent to 3.00 percent per annum for base rate loans, determined by reference to the consolidated leverage ratio (as defined in the 2015 Secured Credit Agreement). 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 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 2015 Revolver as of March 31, 2016 totaled $12.8 million. There were no amounts drawn on the 2015 Revolver as of March 31, 2016.

Note 11 - 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:

	March 31, 2016				December 31, 2015
Dollars in thousands	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term Debt
6.75% Notes	$	360,000	$	255,600	$	360,000	$	246,600
7.50% Notes	225,000		175,500		225,000		171,000
Total Principal	$	585,000	$	431,100	$	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 three months ended March 31, 2016.  

Note 12 - 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 a United States District Court 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. If the Company remains in compliance with the terms of the DPA throughout its effective period, the charge against the Company will be dismissed with prejudice. The Company also settled a related civil complaint filed by the Securities and Exchange Commission (SEC) in a United States District Court. The Company has provided the DOJ annual written reports in connection with the DPA. The third written annual report was filed with the DOJ on April 15, 2016.

Note 13 - Recent Accounting Pronouncements

In March 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (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 are in the process of assessing the impact of the adoption of ASU 2016-09 on our financial position, results of operations and cash flows.

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In March 2016, the FASB issued ASU No. 2016-02,Leases (Topic 842). This update establishes a new lease accounting model for lessees. Early adoption is permitted. 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 becomes effective for public companies for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. 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 selected a transition method nor have we determined the effect of the standard on our ongoing financial reporting.

In November 2015, the FASB issued ASU No. 2015-17,Balance Sheet Classification of Deferred Taxes (Topic 740). This update requires businesses to classify deferred tax liabilities and assets on their balance sheets as noncurrent. Early adoption is permitted. Upon adoption, an entity must apply the new guidance either retrospectively to all prior periods presented in the financial statements prospectively for all new information on a going forward-basis. We early adopted the standard on a retrospective basis as of December 31, 2015.

In September 2015, the FASB issued ASU No. 2015-16,Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments. This new standard specifies that the acquirer should recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined, eliminating the current requirement to retrospectively account for these adjustments. Additionally, the full effect on earnings of changes in depreciation, amortization, or other income effects, if any, as a result of the change to the provisional amounts should be recognized in the same period as the adjustments to the provisional amounts. The standard is effective for all entities for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. We adopted this new standard and there was not a material impact on our financial position, results of operations and cash flows.

In July 2015, the FASB issued ASU No. 2015-11,Inventory (Topic 330): Simplifying the Measurement of Inventory, which requires companies to measure inventory at the lower of cost or net realizable value rather than at the lower of cost or market. Net realizable value is the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. The standard is effective for all entities for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016. We plan to adopt this new standard and do not currently anticipate a material impact on our financial position, results of operations and cash flows.

In June 2015, the FASB issued ASU No. 2015-10, Technical Corrections and Improvements, which contains amendments that will affect a wide variety of topics in the codification. The amendments in this update will apply to all reporting entities within the scope of the affected accounting guidance. Transition guidance varies based on the amendments in the update. The amendments in the update that require transition guidance are effective for all entities for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. Early adoption is permitted, including adoption in an interim period. All other amendments will be effective upon the issuance of this update. We adopted this new standard and there was not a material impact on our financial position, results of operations and cash flows.

In April 2015, the FASB issued ASU No. 2015-03, Interest - Imputation of Interest (Subtopic 835-30): - Simplifying the Presentation of Debt Issuance Costs, which requires debt issuance costs related to a recognized debt liability to be presented in the balance sheet as a direct deduction from the debt liability rather than as an asset. Final guidance on this standard, issued as ASU 2015-15 in August 2015, includes an SEC staff announcement that the SEC staff will not object to an entity presenting the cost of securing a revolving line of credit as an asset, regardless of whether a balance is outstanding. Early adoption is permitted. Upon adoption, an entity must apply the new guidance retrospectively to all prior periods presented in the financial statements. We adopted this standard on a retrospective basis effective January 1, 2016 and it resulted in the netting of $9.8 million of deferred financing costs against long-term debt balances on the consolidated balance sheets for the period ended March 31, 2016 and $10.2 million for the period ended December 31, 2015. We continue to record the deferred financing costs related to our revolving credit facility in “other noncurrent assets” on our consolidated balance sheets for the periods presented. There was no impact to the manner in which deferred financing costs are amortized in our consolidated financial statements.

On May 28, 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 was initially scheduled to be effective for the first quarter of 2017; however, on April 1, 2015, the FASB proposed to defer the effective date by one year and the proposal was accepted during the second quarter of 2015. ASU 2014-09 is now scheduled to be effective for entities 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 14 - 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 March 31, 2016 and December 31, 2015 and for the three months ended March 31, 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 Topic No. 810, Consolidation (ASC 810), we have retrospectively updated the unaudited consolidating condensed financial information as of December 31, 2015 and for the three months ended March 31, 2015.

19

PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATING CONDENSED BALANCE SHEET

(Dollars in Thousands)

(Unaudited)

	March 31, 2016
	Parent			Guarantor			Non-Guarantor			Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	45,822		$	13,242		$	49,363		$	—		$	108,427
Accounts and notes receivable, net	—			48,785			126,597			—			175,382
Rig materials and supplies	—			(3,788		)	40,296			—			36,508
Other current assets	—			5,124			19,314			—			24,438
Total current assets	45,822			63,363			235,570			—			344,755
Property, plant and equipment, net	(19		)	521,959			254,972			—			776,912
Goodwill	—			6,708			—			—			6,708
Intangible assets, net	—			11,164			1,056			—			12,220
Investment in subsidiaries and intercompany advances	3,049,008			2,810,676			3,439,433			(9,299,117		)	—
Other noncurrent assets	(225,185		)	277,015			543,011			(480,787		)	114,054
Total assets	$	2,869,626		$	3,690,885		$	4,474,042		$	(9,779,904	)	$	1,254,649
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	104,789		$	55,216		$	572,465		$	(617,477	)	$	114,993
Accrued income taxes	20,216			(6,430		)	(7,806		)	—			5,980
Total current liabilities	125,005			48,786			564,659			(617,477		)	120,973
Long-term debt, net	575,171			—			—			—			575,171
Other long-term liabilities	2,868			5,867			5,020			—			13,755
Long-term deferred tax liability	(29		)	72,948			(1,021		)	—			71,898
Intercompany payables	1,693,797			1,412,285			1,962,772			(5,068,854		)	—
Total liabilities	2,396,812			1,539,886			2,531,430			(5,686,331		)	781,797
Total equity	472,814			2,150,999			1,942,612			(4,093,573		)	472,852
Total liabilities and stockholders’ equity	$	2,869,626		$	3,690,885		$	4,474,042		$	(9,779,904	)	$	1,254,649

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:
Current portion of long-term debt	$	—		$	—		$	—		$	—		$	—
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
Long-term 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 March 31, 2016
	Parent			Guarantor			Non-Guarantor			Eliminations			Consolidated
Total revenues	$	—		$	47,382		$	106,477		$	(23,356	)	$	130,503
Operating expenses	—			32,835			98,638			(23,356		)	108,117
Depreciation and amortization	—			23,125			12,689			—			35,814
Total operating gross margin	—			(8,578		)	(4,850		)	—			(13,428		)
General and administration expense (1)	(87		)	(9,613		)	(81		)	—			(9,781		)
(Loss) on disposition of assets, net	—			(56		)	(4		)	—			(60		)
Total operating income (loss)	(87		)	(18,247		)	(4,935		)	—			(23,269		)
Other income and (expense):
Interest expense	(11,857		)	(437		)	(2,859		)	3,591			(11,562		)
Interest income	204			179			3,215			(3,591		)	7
Other	—			485			2,000			—			2,485
Equity in net earnings of subsidiaries	(16,225		)	—			—			16,225			—
Total other income (expense)	(27,878		)	227			2,356			16,225			(9,070		)
Income (loss) before income taxes	(27,965		)	(18,020		)	(2,579		)	16,225			(32,339		)
Total income tax expense (benefit)	67,870			(3,707		)	(667		)	—			63,496
Net income (loss)	(95,835		)	(14,313		)	(1,912		)	16,225			(95,835		)
Less: Net income attributable to noncontrolling interest	—			—			—			—			—
Net income (loss) attributable to controlling interest	$	(95,835	)	$	(14,313	)	$	(1,912	)	$	16,225		$	(95,835	)

(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 March 31, 2015
	Parent			Guarantor			Non-Guarantor			Eliminations			Consolidated
Total revenues	$	—		$	79,395		$	150,931		$	(26,250	)	$	204,076
Operating expenses	—			44,145			121,375			(26,250		)	139,270
Depreciation and amortization	—			23,311			17,228			—			40,539
Total operating gross margin	—			11,939			12,328			—			24,267
General and administration expense (1)	(112		)	(10,115		)	(610		)	—			(10,837		)
Gain on disposition of assets, net	—			52			2,389			—			2,441
Total operating income (loss)	(112		)	1,876			14,107			—			15,871
Other income and (expense):
Interest expense	(11,059		)	(17		)	(328		)	326			(11,078		)
Interest income	417			3			89			(326		)	183
Other	—			10			(1,390		)	—			(1,380		)
Equity in net earnings of subsidiaries	8,988			—			—			(8,988		)	—
Total other income (expense)	(1,654		)	(4		)	(1,629		)	(8,988		)	(12,275		)
Income (loss) before income taxes	(1,766		)	1,872			12,478			(8,988		)	3,596
Income tax expense (benefit)	(4,988		)	(447		)	5,253			—			(182		)
Net income (loss)	3,222			2,319			7,225			(8,988		)	3,778
Less: Net income attributable to noncontrolling interest	—			—			556			—			556
Net income (loss) attributable to controlling interest	$	3,222		$	2,319		$	6,669		$	(8,988	)	$	3,222

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

23

PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATING CONDENSED STATEMENT OF COMPREHENSIVE INCOME (LOSS)

(Dollars in Thousands)

(Unaudited)

	Three Months Ended March 31, 2016
	Parent			Guarantor			Non-Guarantor			Eliminations		Consolidated
Comprehensive income:
Net income (loss)	$	(95,835	)	$	(14,313	)	$	(1,912	)	$	16,225	$	(95,835	)
Other comprehensive income (loss), net of tax:
Currency translation difference on related borrowings	—			—			502			—		502
Currency translation difference on foreign currency net investments	—			—			(1,538		)	—		(1,538		)
Total other comprehensive income (loss), net of tax:	—			—			(1,036		)	—		(1,036		)
Comprehensive income (loss)	(95,835		)	(14,313		)	(2,948		)	16,225		(96,871		)
Comprehensive (loss) attributable to noncontrolling interest	—			—			—			—		—
Comprehensive income (loss) attributable to controlling interest	$	(95,835	)	$	(14,313	)	$	(2,948	)	$	16,225	$	(96,871	)

PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATING CONDENSED STATEMENT OF COMPREHENSIVE INCOME (LOSS)

(Dollars in Thousands)

(Unaudited)

	Three Months Ended March 31, 2015
	Parent		Guarantor		Non-Guarantor			Eliminations			Consolidated
Comprehensive income:
Net income (loss)	$	3,222	$	2,319	$	7,225		$	(8,988	)	$	3,778
Other comprehensive income (loss), net of tax:
Currency translation difference on related borrowings	—		—		(1,670		)	—			(1,670		)
Currency translation difference on foreign currency net investments	—		—		(849		)	—			(849		)
Total other comprehensive income (loss), net of tax:	—		—		(2,519		)	—			(2,519		)
Comprehensive income (loss)	3,222		2,319		4,706			(8,988		)	1,259
Comprehensive (loss) attributable to noncontrolling interest	—		—		(394		)	—			(394		)
Comprehensive income (loss) attributable to controlling interest	$	3,222	$	2,319	$	4,312		$	(8,988	)	$	865

24

PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)

(Unaudited)

	Three Months Ended March 31, 2016
	Parent			Guarantor			Non-Guarantor			Eliminations			Consolidated
Cash flows from operating activities:
Net income (loss)	$	(95,835	)	$	(14,313	)	$	(1,912	)	$	16,225		$	(95,835	)
Adjustments to reconcile net income (loss):
Depreciation and amortization	—			23,125			12,689			—			35,814
Accretion of contingent consideration	—			419			—			—			419
Gain on disposition of assets	—			56			4			—			60
Deferred income tax expense	57,677			5,185			549			—			63,411
Expenses not requiring cash	1,740			33			(2,199		)	—			(426		)
Equity in net earnings of subsidiaries	16,225			—			—			(16,225		)	—
Change in assets and liabilities:
Accounts and notes receivable	—			(6,637		)	6,256			—			(381		)
Other assets	(37,191		)	33,904			2,983			—			(304		)
Accounts payable and accrued liabilities	(9,521		)	(799		)	(4,117		)	—			(14,437		)
Accrued income taxes	10,680			(8,905		)	(5,375		)	—			(3,600		)
Net cash provided by (used in) operating activities	(56,225		)	32,068			8,878			—			(15,279		)
Cash flows from investing activities:
Capital expenditures	—			(3,521		)	(4,368		)	—			(7,889		)
Proceeds from the sale of assets	—			28			26			—			54
Net cash provided by (used in) investing activities	—			(3,493		)	(4,342		)	—			(7,835		)
Cash flows from financing activities:
Payment of contingent consideration	—			(2,000		)	—			—			(2,000		)
Excess tax benefit from stock-based compensation	(753		)	—			—			—			(753		)
Intercompany advances, net	28,815			(27,187		)	(1,628		)	—			—
Net cash provided by (used in) financing activities	28,062			(29,187		)	(1,628		)	—			(2,753		)
Net change in cash and cash equivalents	(28,163		)	(612		)	2,908			—			(25,867		)
Cash and cash equivalents at beginning of year	73,985			13,854			46,455			—			134,294
Cash and cash equivalents at end of year	$	45,822		$	13,242		$	49,363		$	—		$	108,427

25

PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)

(Unaudited)

	Three Months Ended March 31, 2015
	Parent			Guarantor			Non-Guarantor			Eliminations			Consolidated
Cash flows from operating activities:
Net income (loss)	$	3,222		$	2,319		$	7,225		$	(8,988	)	$	3,778
Adjustments to reconcile net income (loss)
Depreciation and amortization	—			23,311			17,228			—			40,539
Gain on disposition of assets	—			(52		)	(2,389		)	—			(2,441		)
Deferred income tax expense	(7,932		)	3,117			(1,489		)	—			(6,304		)
Expenses not requiring cash	2,443			436			(1,142		)	—			1,737
Equity in net earnings of subsidiaries	(8,988		)	—			—			8,988			—
Change in assets and liabilities:
Accounts and notes receivable	19			(12,289		)	5,620			—			(6,650		)
Other assets	25,016			(41,216		)	(3,887		)	—			(20,087		)
Accounts payable and accrued liabilities	(10,549		)	47,058			17,536			—			54,045
Accrued income taxes	(10,727		)	13,922			(581		)	—			2,614
Net cash provided by (used in) operating activities	(7,496		)	36,606			38,121			—			67,231
Cash flows from investing activities:
Capital expenditures	—			(24,418		)	(9,037		)	—			(33,455		)
Proceeds from the sale of assets	—			50			196			—			246
Proceeds from insurance settlements	—			—			2,500			—			2,500
Net cash provided by (used in) investing activities	—			(24,368		)	(6,341		)	—			(30,709		)
Cash flows from financing activities:
Repayments of long-term debt	(30,000		)	—			—			—			(30,000		)
Payment of debt issuance costs	(1,359		)	—			—			—			(1,359		)
Excess tax benefit from stock-based compensation	(420		)	—			—			—			(420		)
Intercompany advances, net	34,251			(14,840		)	(19,411		)	—			—
Net cash provided by (used in) financing activities	2,472			(14,840		)	(19,411		)	—			(31,779		)
Net change in cash and cash equivalents	(5,024		)	(2,602		)	12,369			—			4,743
Cash and cash equivalents at beginning of year	36,728			13,546			58,182			—			108,456
Cash and cash equivalents at end of year	$	31,704		$	10,944		$	70,551		$	—		$	113,199

26

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

Management’s discussion and analysis (MD&A) 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).

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, 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;

27

• 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.

28

Executive Overview

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 towards exploratory and development drilling.

Historical market indicators are listed below:

	Three Months Ended March 31,
	2016		2015	% Change
Worldwide Rig Count (1)
U.S. (land and offshore)	555		1,380	(60	)%
International (2)	1,016		1,261	(19	)%
Commodity Prices (3)
Crude Oil (United Kingdom Brent)	$	35.21	55.13	(36	)%
Crude Oil (West Texas Intermediate)	$	33.63	48.57	(31	)%
Natural Gas (Henry Hub)	$	1.98	2.81	(30	)%

(1) Estimate of drilling activity measured by the average active rig count for the period 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.

Executive Outlook

We believe overall energy market conditions will remain at low levels due to the ongoing imbalance between supply and demand for oil and natural gas. Although oil prices have moderately recovered from the recent low set in the first quarter and have begun to trend upward, market fundamentals remain very challenging and the overall industry has not shown any meaningful improvement in activity.

We anticipate further declines in demand and pricing for our rental tools, particularly in the U.S. land and offshore Gulf of Mexico (GOM) drilling markets.  However, the start of new contract commitments in the Middle East plus further cost reductions should help offset some of the decline.

For our U.S. (Lower 48) Drilling segment, we do not anticipate any material changes in activity levels at current commodity prices, so we should see a continuation of low barge utilization levels and dayrates.  In the International & Alaska Drilling Segment, we expect activity to remain low and results to be impacted by lower realized dayrates attributable to both price concessions and more rigs operating in standby mode.  We are also scheduled to complete a significant project services engagement during the second quarter. Despite the challenges we are facing, we extended the term for three rigs in Kazakhstan from mid-2016 out to December 2016 for one rig and for all of 2017 for two rigs.

During the first quarter, one of our two arctic-class drilling rigs in Alaska was placed on standby.  This change in operating status did not impact the first quarter results and is not expected to have a material impact on future results.  We are discussing ways to keep this rig active with our client. Those discussions have been positive and we expect an agreement to be concluded soon. In the event an agreement is not reached and the rig is released, our contract provides for an early termination fee.

Although we do not know the depth or duration of this downcycle, we have taken steps to align resources with the ongoing market downturn by lowering our cost base, sustaining our utilization, and managing our cash and 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.

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Results of Operations

Our business is comprised of two business lines: (1) Drilling Services and (2) Rental Tools Services. We report our Rental Tools Services business as one reportable segment (Rental Tools) and report our Drilling Services business as two reportable segments: (1) U.S. (Lower 48) Drilling and (2) International & Alaska Drilling. 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 our consolidated financial statements. See Note 7 - Reportable Segments in Item 1. Financial Statements and Supplementary Data for further discussion. 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 may provide additional, meaningful comparisons between current results and results of prior periods to users of this financial information.

Three Months Ended March 31, 2016 Compared with Three Months Ended March 31, 2015

Revenues decreased $73.6 million, or 36.1 percent, to $130.5 million for the three months ended March 31, 2016 as compared to revenues of $204.1 million for the three months ended March 31, 2015. Operating gross margin decreased $37.7 million, or 155.1 percent, to a loss of $13.4 million, for the three months ended March 31, 2016 as compared to income of $24.3 million for the three months ended March 31, 2015.

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

	Three Months Ended March 31,
Dollars in Thousands	2016					2015
Revenues:
Drilling Services:
U.S. (Lower 48) Drilling	$	2,085		2	%	$	14,097		7	%
International & Alaska Drilling	88,619			68	%	113,921			56	%
Total Drilling Services	90,704			70	%	128,018			63	%
Rental Tools	39,799			30	%	76,058			37	%
Total revenues	130,503			100	%	204,076			100	%
Operating gross margin (loss) excluding depreciation and amortization:
Drilling Services:
U.S. (Lower 48) Drilling	(3,337		)	n/m		115			1	%
International & Alaska Drilling	18,894			21	%	35,392			31	%
Total Drilling Services	15,557			17	%	35,507			28	%
Rental Tools	6,829			17	%	29,299			39	%
Total operating gross margin excluding depreciation and amortization	22,386			17	%	64,806			32	%
Depreciation and amortization	(35,814		)			(40,539		)
Total operating gross margin	(13,428		)			24,267
General and administrative expense	(9,781		)			(10,837		)
Gain (loss) on disposition of assets, net	(60		)			2,441
Total operating income (loss)	$	(23,269	)			$	15,871

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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		Rental Tools			Total
Three Months Ended March 31, 2016
Operating gross margin (1)	$	(8,558	)	$	5,077	$	(9,947	)	$	(13,428	)
Depreciation and amortization	5,221			13,817		16,776			35,814
Operating gross margin excluding depreciation and amortization	$	(3,337	)	$	18,894	$	6,829		$	22,386
Three Months Ended March 31, 2015
Operating gross margin (1)	$	(5,717	)	$	17,354	$	12,630		$	24,267
Depreciation and amortization	5,832			18,038		16,669			40,539
Operating gross margin excluding depreciation and amortization	$	115		$	35,392	$	29,299		$	64,806

(1) Operating gross margin 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 March 31, 2016 and 2015, respectively:

	Three Months Ended March 31,
	2016		2015
U.S. (Lower 48) Drilling
Rigs available for service (1)	13.0		13.0
Utilization rate of rigs available for service (2)	7	%	21	%
International & Alaska Drilling
Eastern Hemisphere
Rigs available for service (1)	13.0		13.0
Utilization rate of rigs available for service (2)	48	%	82	%
Latin America Region
Rigs available for service (1)	7.0		9.0
Utilization rate of rigs available for service (2)	29	%	45	%
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)	46	%	70	%

(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 Line

U.S. (Lower 48) Drilling

U.S. (Lower 48) Drilling segment revenues decreased $12.0 million, or 85.1 percent, to $2.1 million for the first quarter of 2016 compared with revenues of $14.1 million for the first quarter of 2015. The decrease was primarily due to lower utilization in the inland waters of the GOM, which declined from 21 percent for the quarter ended March 31, 2015 to 7 percent for the quarter ended March 31, 2016 and resulted in a $6.3 million decrease in revenue. The decline in utilization for the barge drilling business was due to substantial reductions in drilling activity by operators in the inland waters of the GOM resulting from lower oil prices. The remainder of the decrease was primarily driven by a decrease in revenues of $4.2 million from our O&M contract supporting three platform operations located offshore California, as the O&M contract ended during the 2015 fourth quarter.

U.S. (Lower 48) Drilling segment operating gross margin excluding depreciation and amortization decreased $3.4 million to a loss of $3.3 million for the first quarter of 2016 compared with income of $0.1 million for the first quarter of 2015. The decrease was primarily due to the decline in utilization and the ending of the O&M contract discussed above.

International & Alaska Drilling

International & Alaska Drilling segment revenues decreased $25.3 million, or 22.2 percent, to $88.6 million for the first quarter of 2016 compared with $113.9 million for the first quarter of 2015.

The decrease in revenues was primarily due to the following:

• a decrease of $24.0 million resulting from decreased utilization for Parker-owned rigs. Utilization for the segment decreased to 46 percent for the quarter ended March 31, 2016 from 70 percent for the quarter ended March 31, 2015, primarily resulting from the continued impact of the decline in oil prices which led to reduced customer activity; and

• a decrease of $3.2 million related to demobilization revenue earned in the first quarter of 2015 that did not recur in the first quarter of 2016.

The decrease in revenues was partially offset by an increase of $5.1 million of revenues generated from our project service activities.

International & Alaska Drilling segment operating gross margin excluding depreciation and amortization decreased $16.5 million, or 46.6 percent, to $18.9 million for the first quarter of 2016 compared with $35.4 million for the first quarter of 2015. The decrease in operating gross margin excluding depreciation and amortization was primarily due to the impact of lower utilization discussed above.

Rental Tools Services Business Line

Rental Tools segment revenues decreased $36.3 million, or 47.7 percent, to $39.8 million for the first quarter of 2016 compared with $76.1 million for the first quarter of 2015. The decrease was due to a $23.3 million decrease in our U.S. revenues and a $13.0 million decrease in our international revenues. The decreases were primarily attributable to the continued reduction in customer activity and pricing pressures resulting from lower oil prices.

Rental Tools segment operating gross margin excluding depreciation and amortization decreased $22.5 million, or 76.8 percent, to $6.8 million in the first quarter of 2016 compared with $29.3 million for the first quarter of 2015. The decrease in operating gross margin excluding depreciation and amortization primarily consists of a $13.8 million decrease for our U.S. operations and an $8.7 million decrease for our international operations, in both cases the decrease was due to the declines in oil prices and customer activity discussed above.

Other Financial Data

General and administrative expense

General and administration expense decreased $1.0 million to $9.8 million for the first quarter of 2016, compared with $10.8 million for the first quarter of 2015. General and administrative expense in the first quarter of 2015 was primarily driven by increased expenses as we implemented the second phase of our new enterprise resource planning system during the quarter. Additionally, general and administrative expense in the first quarter of 2016 benefited from cost savings initiatives.

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Gain/loss on disposition of assets

Net losses recognized on asset dispositions were nominal during the first quarter of 2016, compared with net gains of $2.4 million during the first quarter of 2015. The net gains for the first quarter of 2015 were primarily due to an insurance settlement received during the quarter 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 $0.5 million to $11.6 million for the first quarter of 2016 compared with $11.1 million for the first quarter of 2015. The increase in interest expense is a result of the accretion of the contingent consideration related to the acquisition of 2M-Tek, a Louisiana-based manufacturer of equipment for tubular running and related well services (the 2M-Tek Acquisition). Interest income during each of the 2016 and 2015 first quarters was nominal.

Other income and expense

Other income for the first quarter of 2016 was $2.5 million compared with other expense for the first quarter of 2015 of $1.4 million. Other income for the first quarter of 2016 was primarily attributable to a reclassification of $1.9 million of realized foreign currency translation gains from accumulated other comprehensive income (AOCI) and the settlement of certain legal claims, resulting in other income, of $0.6 million. Other expense for the first quarter of 2015 was primarily driven by losses related to foreign currency fluctuations.

Income tax expense (benefit)

During the first quarter of 2016 we had income tax expense of $63.5 million compared to a tax benefit of $0.2 million during the first quarter of 2015.  Despite the pre-tax operating loss for the first quarter of 2016, we recognized income tax expense as a result of recording a valuation allowance of $73.1 million against our U.S. domestic deferred tax assets, which primarily consist of U.S. federal net operating losses.  We established the valuation allowance based on the weight of positive and negative evidence available, including the recent and current results of operations which reflect continued degradation in market activity and including the increased contractual uncertainty materializing during the first quarter of 2016 in the U.S. jurisdictions in which we operate. In order to determine the need for a valuation allowance, we must make estimates and assumptions regarding events occurring in the first quarter of 2016.  Changes in these estimates and assumptions, including changes in tax laws and other changes impacting our ability to recognize the underlying deferred tax assets, may require us to adjust the valuation allowances in the future. The income tax benefit in the first quarter of 2015 was primarily related to changes in the carrying value of certain deferred tax assets due to changes in tax law and taxing jurisdictions.    

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 $228 million at March 31, 2016 and $495 million at March 31, 2015 and is primarily attributable to the International & Alaska segment of our Drilling Services business. We estimate that, as of March 31, 2016, 51 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 2015 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 necessary we may seek to raise additional capital in the future. We do not pay dividends to our shareholders.

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Liquidity

The following table provides a summary of our total liquidity:

	March 31, 2016
Dollars in thousands
Cash and cash equivalents on hand (1)	$	108,427
Availability under 2015 Revolver (2), (3)	187,165
Total liquidity	$	295,592

(1) As of March 31, 2016, approximately $46.6 million of the $108.4 million of cash and equivalents was held by our foreign subsidiaries.

(2) Availability under the 2015 Revolver included $200 million undrawn portion of our 2015 Revolver less $12.8 million of letters of credit outstanding.

(3) In order to access the 2015 Revolver, we must be in compliance with the covenants contained in the 2015 Secured Credit Agreement. The consolidated leverage ratio covenant currently limits our ability to borrow under the 2015 Secured Credit Agreement and remain in compliance with the covenant.  If a transaction were to occur, the pro-forma results of the transaction would be included in the consolidated leverage ratio calculation on a trailing twelve-month basis. As conditions in the oil and gas industry continue to decline, we continue to engage in discussions with our lenders regarding certain covenants and restrictions in the 2015 Secured Credit Agreement.  We are currently seeking to amend our 2015 Secured Credit Agreement to ensure we remain in compliance and expect to have an amendment complete before the end of the second quarter.  While we expect the amendment to provide covenant relief and flexibility, we also expect a reduction in size of the credit facility as part of the agreed amendment.

The earnings of foreign subsidiaries as of March 31, 2016 were reinvested to fund our international operations.  If in the future we decide to repatriate earnings to the United States, the Company may be required to pay taxes on these amounts based on applicable United States 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 March 31, 2016, we have no energy, commodity, or foreign currency derivative contracts.

Cash Flow Activity

As of March 31, 2016, we had cash and cash equivalents of $108.4 million, a decrease of $25.9 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:

	Three Months Ended March 31, 2016
Dollars in thousands	2016			2015
Operating Activities	$	(15,279	)	$	67,231
Investing Activities	(7,835		)	(30,709		)
Financing Activities	(2,753		)	(31,779		)
Net change in cash and cash equivalents	$	(25,867	)	$	4,743

Operating Activities

Cash flows for operating activities were a use of $15.3 million for the three months ended March 31, 2016 compared to a source of $67.2 million for the three months ended March 31, 2015. Cash flows for operating activities in each quarter were largely impacted by our earnings and changes in working capital. Changes in working capital were a use of cash of $18.7 million for the three months ended March 31, 2016 compared to a source of cash of $29.9 million for the three months ended March 31, 2015. In addition to the impact of earnings and working capital changes cash flows for operating activities in each quarter were impacted by non-cash charges such as depreciation expense, gains on asset sales, deferred tax benefit, stock compensation expense, debt extinguishment 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.

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Investing Activities

Cash flows used in investing activities were $7.8 million for the three months ended March 31, 2016 compared with $30.7 million for the three months ended March 31, 2015. Our primary use of cash during the three months ended March 31, 2016 and 2015 was $7.9 million and $33.5 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.

Financing Activities

Cash flows used in financing activities were $2.8 million for the three months ended March 31, 2016, primarily due to the payment of $2.0 million of the contingent consideration related to the 2M-Tek Acquisition. The payment was made upon the achievement of certain milestones during the first quarter of 2016. Cash flows used in financing activities were $31.8 million for the 2015 comparable period, primarily driven by the repayment of the $30.0 million term loan in the first quarter of 2015.

Long-Term Debt Summary

Our principal amount of long-term debt, including current portion, was $575.2 million as of March 31, 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

•$9.8 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 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 (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 ($6.0 million net of amortization as of March 31, 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. 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.

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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 ($3.8 million, net of amortization as of March 31, 2016) are being amortized over the term of the notes using the effective interest rate method.

At any time prior to August 1, 2016, we may redeem up to 35 percent of the aggregate principal amount of the 7.50% Notes at a redemption price of 107.50 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. 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. 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 is comprised of a $200.0 million revolving credit facility (2015 Revolver) and matures on January 26, 2020. The 2012 Secured Credit Agreement consisted of an $80.0 million revolving credit facility and a $50.0 million term loan. At the closing of the 2015 Secured Credit Agreement, the outstanding balance on the term loan was $30.0 million, and we repaid this balance with a $30.0 million draw on the 2015 Revolver. On June 1, 2015, we executed the first amendment to the 2015 Secured Credit Agreement in order to amend certain provisions of the 2015 Secured Credit Agreement regarding the definition of “Change of Control.” On September 29, 2015, we executed the second amendment to the 2015 Secured Credit Agreement (the “Second Amendment”). Among other things, the Second Amendment: (a) gradually increases the permissible consolidated leverage ratio from a maximum of 4.00:1.00 to 5.75:1.00 through December 31, 2016, which thereafter gradually reduces to 4.00:1.00 by December 31, 2017; (b) reduces the consolidated interest coverage ratio from 2.50:1:00 to 2.25:1.00 for each quarter of 2016, and returning to 2.50:1.00 thereafter; (c) increases the Applicable Rate for certain higher levels of consolidated leverage to a maximum of 4.00 percent per annum for LIBOR rate loans and to 3.00 percent per annum for base rate loans; (d) allows multi-year letters of credit up to an aggregate amount of $5 million; (e) limits payment prior to September 30, 2017 of certain restricted payments and certain prepayments of unsecured senior notes and other specified forms of indebtedness; and (f) removes the option of the Company, subject to the consent of the lenders, to increase the Credit Agreement up to an additional $75 million. We incurred debt issuance costs related to the 2015 Secured Credit Agreement of approximately $2.0 million and had approximately $0.8 million of remaining debt issuance costs for the 2012 Secured Credit agreement. The total debt issuance costs of $2.8 million ($2.3 million, net of amortization as of March 31, 2016) are being amortized over the term of the 2015 Secured Credit Agreement on a straight line basis.

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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 (including a minimum asset coverage ratio of 1.25:1.00 at each quarter end, a consolidated leverage ratio, as described above, a consolidated interest coverage ratio, as described above, and a maximum senior secured leverage ratio of 1.50:1:00 at each quarter end). We were in compliance with all such covenants as of March 31, 2016.

Our 2015 Revolver is available for general corporate purposes and to support letters of credit. Interest on 2015 Revolver loans accrues at a Base Rate plus an Applicable Rate or LIBOR plus an Applicable Rate. As a result of the Second Amendment, the Applicable Rate ranges from 2.50 percent to 4.00 percent per annum for LIBOR rate loans and from 1.50 percent to 3.00 percent per annum for base rate loans, determined by reference to the consolidated leverage ratio (as defined in the 2015 Secured Credit Agreement). 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 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 2015 Revolver as of March 31, 2016 totaled $12.8 million. There were no amounts drawn on the 2015 Revolver as of March 31, 2016.

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 March 31, 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

The SEC’s rules permit the exclusion of an assessment of the effectiveness of a registrant’s disclosure controls and procedures as they relate to its internal controls over financial reporting for an acquired business during the first year following such acquisition, if among other circumstances and factors there is not adequate time between the acquisition date and the date of assessment. As previously noted in this Form 10-Q, we completed the 2M-Tek Acquisition on April 17, 2015. 2M-Tek represents approximately 1.3 percent of our total assets as of March 31, 2016 and approximately 0 percent and 0.4 percent of revenues and net income (loss), respectively, for the three-month period then ended. The 2M-Tek Acquisition did not have a material impact on internal control over financial reporting. Management's assessment and conclusion on the effectiveness of the Company’s disclosure controls and procedures as of March 31, 2016 excluded an assessment of the internal control over financial reporting of 2M-Tek. We are in the process of reviewing 2M-Tek’s internal controls and processes and of extending to 2M-Tek our Section 404 compliance program under the Sarbanes-Oxley Act of 2002 and the applicable rules and regulations under such Act. Other than changes resulting from the 2M-Tek Acquisition discussed above, 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 12, “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).
10.1	—	Form of Parker Drilling Company Time-Based Phantom Stock Unit Award Incentive Agreement under the 2010 LTIP (as amended and restated effective May 8, 2013).*
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.

39

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:	May 4, 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).
10.1	—	Form of Parker Drilling Company Time-Based Phantom Stock Unit Award Incentive Agreement under the 2010 LTIP (as amended and restated effective May 8, 2013).*
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.

41