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 June 30, 2017

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, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer		¨		Accelerated filer		x
Non-accelerated filer		¨ (Do not check if a smaller reporting company)		Smaller reporting company		¨
				Emerging growth company		¨

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ¨    No  x

As of August 1, 2017 there were 138,255,177 common shares outstanding.    

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TABLE OF CONTENTS

 

	Page
Part I. Financial Information
Item 1. Financial Statements	3
Consolidated Condensed Balance Sheets as of June 30, 2017 (Unaudited) and December 31, 2016	3
Consolidated Condensed Statements of Operations (Unaudited) for the Three and Six Months Ended June 30, 2017 and 2016	4
Consolidated Condensed Statements of Comprehensive Income (Loss) (Unaudited) for the Three and Six Months Ended June 30, 2017 and 2016	5
Consolidated Condensed Statements of Cash Flows (Unaudited) for the Six Months Ended June 30, 2017 and 2016	6
Consolidated Condensed Statement of Stockholders’ Equity (Unaudited) for the Six months ended June 30, 2017	7
Notes to the Unaudited Consolidated Condensed Financial Statements	8
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	32
Item 3. Quantitative and Qualitative Disclosures about Market Risk	46
Item 4. Controls and Procedures	46
Part II. Other Information
Item 1. Legal Proceedings	47
Item 1A. Risk Factors	47
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	47
Item 3. Defaults Upon Senior Securities	47
Item 4. Mine Safety Disclosures	47
Item 5. Other Information	47
Item 6. Exhibits	48
Signatures	49

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PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATED CONDENSED BALANCE SHEETS

(Dollars in Thousands) 

	June 30, 2017				December 31, 2016
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	146,234			$	119,691
Accounts and Notes Receivable, net of allowance for bad debts of $7,912 at June 30, 2017 and $8,259 at December 31, 2016.	120,070				113,231
Rig materials and supplies	35,270				32,354
Other current assets	25,708				21,042
Total current assets	327,282				286,318
Property, plant and equipment, net of accumulated depreciation of $1,312,421 at June 30, 2017 and $1,320,644 at December 31, 2016.	667,042				693,439
Goodwill	6,708				6,708
Intangible assets, net	8,470				9,928
Deferred income taxes	79,152				70,309
Other noncurrent assets	33,452				36,849
Total assets	$	1,122,106			$	1,103,551
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities	106,303				98,841
Accrued income taxes	5,136				4,080
Total current liabilities	111,439				102,921
Long-term debt, net of unamortized debt issuance costs of $7,867 at June 30, 2017 and $8,674 at December 31, 2016.	577,133				576,326
Other long-term liabilities	12,518				15,836
Deferred tax liability	77,221				69,333
Commitments and contingencies (Note 11)
Stockholders’ equity:
Preferred Stock, $1.00 par value, 1,942,000 shares authorized, 7.25% Series A Mandatory Convertible, 500,000 shares issued and outstanding (none in 2016)	500				—
Common Stock, $0.16 2/3 par value, 280,000,000 shares authorized; 138,251,008 shares issued and outstanding (125,118,365 shares in 2016)	23,026				20,837
Capital in excess of par value	745,145				675,194
Accumulated deficit	(419,749		)		(350,052		)
Accumulated other comprehensive income (loss)	(5,127		)		(6,844		)
Total stockholders’ equity	343,795				339,135
Total liabilities and stockholders’ equity	$	1,122,106			$	1,103,551

See accompanying notes to the unaudited consolidated condensed financial statements.

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PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENTS OF OPERATIONS

(Dollars in Thousands, Except Per Share Data)

(Unaudited)

 

	Three Months Ended June 30,								Six Months Ended June 30,
	2017				2016				2017				2016
Revenues	$	109,607			$	105,287			$	207,878			$	235,790
Expenses:
Operating expenses	89,641				89,195				175,455				197,312
Depreciation and amortization	30,982				36,317				63,184				72,131
	120,623				125,512				238,639				269,443
Total operating gross margin (loss)	(11,016		)		(20,225		)		(30,761		)		(33,653		)
General and administrative expense	(6,503		)		(7,995		)		(13,543		)		(17,776		)
Gain (loss) on disposition of assets, net	(113		)		(2		)		(465		)		(62		)
Total operating income (loss)	(17,632		)		(28,222		)		(44,769		)		(51,491		)
Other income (expense):
Interest expense	(11,095		)		(12,187		)		(21,965		)		(23,749		)
Interest income	22				32				32				39
Other	560				(358		)		1,090				2,127
Total other income (expense)	(10,513		)		(12,513		)		(20,843		)		(21,583		)
Income (loss) before income taxes	(28,145		)		(40,735		)		(65,612		)		(73,074		)
Income tax expense (benefit)	1,743				(913		)		4,085				62,583
Net income (loss)	(29,888		)		(39,822		)		(69,697		)		(135,657		)
Less: Mandatory convertible preferred stock dividend	1,239				—				1,239				—
Net income (loss) available to common stockholders	$	(31,127	)		$	(39,822	)		$	(70,936	)		$	(135,657	)
Basic income (loss) per common share	$	(0.23	)		$	(0.32	)		$	(0.53	)		$	(1.10	)
Diluted income (loss) per common share	$	(0.23	)		$	(0.32	)		$	(0.53	)		$	(1.10	)
Number of common shares used in computing earnings per share:
Basic	137,833,318				124,101,349				134,009,168				123,595,793
Diluted	137,833,318				124,101,349				134,009,168				123,595,793

See accompanying notes to the unaudited consolidated condensed financial statements.

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PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Dollars in Thousands)

(Unaudited)

 

	Three Months Ended June 30,								Six Months Ended June 30,
	2017				2016				2017				2016
Comprehensive income (loss):
Net income (loss)	$	(29,888	)		$	(39,822	)		$	(69,697	)		$	(135,657	)
Other comprehensive income (loss), net of tax:
Currency translation difference on related borrowings	185				(307		)		268				195
Currency translation difference on foreign currency net investments	686				(2,228		)		1,449				(3,766		)
Total other comprehensive income (loss), net of tax:	871				(2,535		)		1,717				(3,571		)
Comprehensive income (loss)	(29,017		)		(42,357		)		(67,980		)		(139,228		)

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)

	Six Months Ended June 30,
	2017				2016
Cash flows from operating activities:
Net income (loss)	$	(69,697	)		$	(135,657	)
Adjustments to reconcile net income (loss)
Depreciation and amortization	63,184				72,131
Accretion of contingent consideration	—				419
(Gain) loss on debt modification	—				1,088
(Gain) loss on disposition of assets	465				62
Deferred income tax expense (benefit)	(934		)		59,305
Excess tax benefit (expense) from stock-based compensation	—				(1,617		)
Expenses not requiring cash	4,948				(4,409		)
Change in assets and liabilities:
Accounts and notes receivable	(6,853		)		22,319
Other assets	(1,722		)		(2,992		)
Accounts payable and accrued liabilities	(8,235		)		(6,862		)
Accrued income taxes	1,276				(3,985		)
Net cash provided by (used in) operating activities	(17,568		)		(198		)
Cash flows from investing activities:
Capital expenditures	(26,559		)		(16,257		)
Proceeds from the sale of assets	185				1,387
Net cash provided by (used in) investing activities	(26,374		)		(14,870		)
Cash flows from financing activities:
Payment for noncontrolling interest	—				(3,375		)
Payments of contingent consideration	—				(6,000		)
Proceeds from the issuance of common stock	25,200				—
Proceeds from the issuance of mandatory convertible preferred stock	50,000				—
Payment of equity issuance costs	(2,864		)		—
Mandatory convertible preferred stock dividend	(1,239		)		—
Shares surrendered in lieu of tax	(612		)		(817		)
Net cash provided by (used in) financing activities	70,485				(10,192		)
Net increase (decrease) in cash and cash equivalents	26,543				(25,260		)
Cash and cash equivalents, beginning of year	119,691				134,294
Cash and cash equivalents, end of period	$	146,234			$	109,034
Supplemental cash flow information:
Interest paid	$	20,588			$	20,588
Income taxes paid	$	4,262			$	9,672

See accompanying notes to the unaudited consolidated condensed financial statements.

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PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENTS OF STOCKHOLDERS’ EQUITY

(Dollars and Shares in Thousands)

(Unaudited)

	Shares			Preferred Stock				Common Stock				Treasury Stock				Capital in Excess of Par Value				Accumulated Deficit				Accumulated Other Comprehensive Income (Loss)				Total Stockholders’ Equity
Balances, December 31, 2016	125,118			$	—			$	21,007			$	(170	)		$	675,194			$	(350,052	)		$	(6,844	)		$	339,135
Activity in employees’ stock plans	1,133			—				189				—				(864		)		—				—				(675		)
Amortization of stock-based awards	—			—				—				—				2,218				—				—				2,218
Issuance of common stock	12,000			—				2,000				—				22,059				—				—				24,059
Issuance of mandatory convertible preferred stock	500			500				—				—				47,777				—				—				48,277
Mandatory convertible preferred stock dividend	—			—				—				—				(1,239		)		—				—				(1,239		)
Comprehensive Income:				—
Net income (loss)	—			—				—				—				—				(69,697		)		—				(69,697		)
Other comprehensive income (loss)	—			—				—				—				—				—				1,717				1,717
Balances, June 30, 2017	138,751			$	500			$	23,196			$	(170	)		$	745,145			$	(419,749	)		$	(5,127	)		$	343,795

See accompanying notes to the unaudited consolidated condensed financial statements.

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PARKER DRILLING COMPANY AND SUBSIDIARIES

NOTES TO THE UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

Note 1 - General

The Consolidated Condensed Financial Statements as of June 30, 2017 and for the three and six months ended June 30, 2017 and 2016 are unaudited. In the opinion of Parker Drilling Company (Parker Drilling or the Company), these financial statements include all adjustments, which, unless otherwise disclosed, are of a normal recurring nature, necessary for a fair presentation of the financial position, results of operations, comprehensive income, cash flows, and stockholders’ equity for the periods presented. The results for interim periods are not necessarily indicative of results for the entire year. The financial statements presented herein should be read in connection with the financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2016.

Nature of Operations — Our business is comprised of two business lines: (1) Drilling Services and (2) Rental Tools Services. We report our Drilling Services business as two reportable segments: (1) U.S. (Lower 48) Drilling and (2) International & Alaska Drilling. We report our Rental Tools Services business as two reportable segments: (1) U.S. Rental Tools and (2) International Rental Tools.

In our Drilling Services business, we drill oil, natural gas and geothermal 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 management (O&M) service in which operators own their own drilling rigs but choose Parker Drilling to operate and manage the rigs for them. The nature and scope of activities involved in drilling an oil and natural 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.

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

Consolidation — The consolidated financial statements include the accounts of the Company and subsidiaries in which we exercise control or 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 condensed statements of operations.

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

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

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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 $15.2 million and $18.9 million for the three months ended June 30, 2017 and 2016, respectively, and $30.5 million and $37.9 million for the six months ended June 30, 2017 and 2016, respectively. Additionally, the Company typically receives a nominal handling fee, which is recognized as earned in 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.

Goodwill — We perform our annual goodwill impairment review during the fourth quarter, as of October 1, and more frequently if negative conditions or other triggering events arise. The quantitative impairment test we perform for goodwill utilizes certain assumptions, including forecasted revenues and costs assumptions. See Note 2 - 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 classified as definite lived intangibles, that 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 2 - 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 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 34.0 percent of our consolidated revenues for the six months ended June 30, 2017. Excluding reimbursable revenues of $27.0 million, ENL constituted approximately 24.6 percent of our total consolidated revenues for the six months ended June 30, 2017. Our second largest customer, BP Exploration Alaska, Inc. (BP), constituted approximately 10.5 percent of our consolidated revenues for the six months ended June 30, 2017.

At June 30, 2017 and December 31, 2016, we had deposits in domestic banks in excess of federally insured limits of approximately $106.3 million and $81.4 million, respectively. In addition, we had uninsured deposits in foreign banks as of June 30, 2017 and December 31, 2016 of $40.4 million and $39.7 million, respectively.    

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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.

Earnings (Loss) Per Share (EPS) —Basic earnings (loss) per share is computed by dividing net income (loss) available to common shareholders by the weighted average number of common shares outstanding during the period. The effects of dilutive securities, stock options, unvested restricted stock, convertible debt and equity are included in the diluted EPS calculation, when applicable.

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 - Goodwill and Intangible Assets    

We account for business combinations using the acquisition method of accounting. Under this method, assets and liabilities, including any remaining noncontrolling interests, are recognized at fair value at the date of acquisition. The excess of the purchase price over the fair value of assets acquired, net of liabilities assumed, plus the value of any noncontrolling interests, is recognized as goodwill. We perform our annual goodwill impairment review during the fourth quarter, as of October 1, and more frequently if negative conditions or other triggering events arise. Should current market conditions worsen or persist for an extended period of time, an impairment of the carrying value of our goodwill could occur.

All of the Company’s goodwill and intangible assets are allocated to the International Rental Tools segment.

Goodwill

The change in the carrying amount of goodwill for the period ended June 30, 2017 is as follows:

Dollars in thousands		Goodwill
Balance at December 31, 2016		$	6,708
Additions		—
Balance at June 30, 2017		$	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 June 30, 2017
Dollars in thousands	Estimated Useful Life (Years)	Gross Carrying Amount				Write-off Due to Disposal				Accumulated Amortization				Net Carrying Amount
Amortized intangible assets:
Developed technology	6	$	11,630			$	—			$	(4,362	)		$	7,268
Customer relationships	3	5,400				(264		)		(5,136		)		—
Trade names	5	4,940				(332		)		(3,406		)		1,202
Total amortized intangible assets		$	21,970			$	(596	)		$	(12,904	)		$	8,470

Amortization expense was $1.5 million and $2.0 million for the six months ended June 30, 2017 and 2016, respectively.

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

Dollars in thousands	Expected future intangible amortization expense
2017	$	1,343
2018	$	2,306
2019	$	2,306
2020	$	2,030
2021	$	485

Note 3 - Earnings (Loss) Per Share (EPS)

Basic earnings (loss) per share is computed by dividing net income (loss) available to common shareholders by the weighted average number of common shares outstanding during the period. The effects of dilutive securities, stock options, unvested restricted stock, convertible debt and equity are included in the diluted EPS calculation, when applicable.

The following table represents the computation of earnings per share for the three and six months ended June 30, 2017 and 2016, respectively:

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	Three Months Ended June 30, 2017
	Net Income (Loss) Available to Common Stockholders (Numerator)				Shares (Denominator)			Per-Share Amount
Basic earnings (loss) per common share	$	(31,127,000	)		137,833,318			$	(0.23	)
Effect of dilutive securities:
Restricted stock units (1)	—				—			—
Mandatory convertible preferred stock (2)	—				—			—
Diluted earnings (loss) per common share	$	(31,127,000	)		137,833,318			$	(0.23	)
	Six Months Ended June 30, 2017
	Income/(Loss) (Numerator)				Shares (Denominator)			Per-Share Amount
Basic earnings (loss) per common share	$	(70,936,000	)		134,009,168			$	(0.53	)
Effect of dilutive securities:
Restricted stock units (1)	—				—			—
Mandatory convertible preferred stock (2)	—				—			—
Diluted earnings (loss) per common share	$	(70,936,000	)		134,009,168			$	(0.53	)
	Three Months Ended June 30, 2016
	Net Income (Loss) Available to Common Stockholders (Numerator)				Shares (Denominator)			Per-Share Amount
Basic earnings (loss) per common share	$	(39,822,000	)		124,101,349			$	(0.32	)
Effect of dilutive securities:
Restricted stock units (1)	—				—			—
Diluted earnings (loss) per common share	$	(39,822,000	)		124,101,349			$	(0.32	)
	Six Months Ended June 30, 2016
	Income/(Loss) (Numerator)				Shares (Denominator)			Per-Share Amount
Basic earnings (loss) per common share	$	(135,657,000	)		123,595,793			$	(1.10	)
Effect of dilutive securities:
Restricted stock units (1)	—				—			—
Diluted earnings (loss) per common share	$	(135,657,000	)		123,595,793			$	(1.10	)

(1)    For the three and six months ended June 30, 2017 and 2016, respectively, all common shares potentially issuable in connection with outstanding restricted stock unit awards have been excluded from the calculation of diluted EPS as the company incurred losses during the periods, therefore, inclusion of such potential common shares would be anti-dilutive.

(2)     Weighted average common shares issuable upon the assumed conversion of our Mandatory Convertible Preferred Stock totaling 23,809,500 shares were excluded from the computation of diluted EPS as such shares would be anti-dilutive.

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Note 4 - Common and Preferred Stock Issuances

In February 2017, we issued 12,000,000 shares of common stock, par value $0.16 2/3 per share, at the public offering price of $2.10 per share, and 500,000 shares of 7.25% Series A Mandatory Convertible Preferred Stock (Convertible Preferred Stock), par value $1.00 per share, with a liquidation preference of $100 per share, for total net proceeds of $72.3 million, after underwriting discount and offering expenses.

The dividends on our Convertible Preferred Stock will be payable on a cumulative basis when, as and if declared by our board of directors, or an authorized committee of our board of directors, at an annual rate of 7.25 percent of the liquidation preference of $100 per share. We may pay declared dividends in cash or, subject to certain limitations, in shares of our common stock, or in any combination of cash and shares of our common stock on March 31, June 30, September 30 and December 31 of each year, commencing on June 30, 2017 and ending on, and including, March 31, 2020.

Unless converted earlier, each share of our Convertible Preferred Stock will automatically convert into between  41.4079 and 47.6190 shares of our common stock (respectively, the “minimum conversion rate” and “maximum conversion rate”), subject to anti-dilution adjustments. The number of shares of our common stock issuable on conversion will be determined based on the volume weighted-average price, of our common stock over the 20 consecutive trading day period beginning on, and including, the 23rd scheduled trading day immediately preceding March 31, 2020. Except in limited circumstances, at any time prior to March 31, 2020, a holder may convert Convertible Preferred Stock into shares of our common stock at the minimum conversion rate of 41.4079 shares of common stock per share of Convertible Preferred Stock, subject to anti-dilution adjustments.

On May 9, 2017, our board of directors declared a cash dividend of $2.4771 per share of our Convertible Preferred Stock for the period from and including February 22, 2017 through and including June 29, 2017, which was paid on June 30, 2017 to mandatory convertible preferred shareholders of record as of June 15, 2017. On August 3, 2017, the Audit Committee, on behalf of our board of directors, declared a cash dividend of $1.8125 per share of our Convertible Preferred Stock for the period from and including June 30, 2017 through and including September 29, 2017, which is scheduled to be paid on September 30, 2017 to mandatory convertible preferred shareholders of record as of September 15, 2017.

Note 5 - Accumulated Other Comprehensive Income (Loss)

Accumulated other comprehensive loss consisted of the following:

Dollars in thousands	Foreign Currency Items
December 31, 2016	$	(6,844	)
Current period other comprehensive income (loss)	1,717
June 30, 2017	$	(5,127	)

There were no amounts reclassified out of accumulated other comprehensive loss for the three months ended June 30, 2017.

Note 6 - Reportable Segments

Our business is comprised of two business lines: (1) Drilling Services and (2) Rental Tools Services. We report our Drilling Services business as two reportable segments: (1) U.S. (Lower 48) Drilling and (2) International & Alaska Drilling. We report our Rental Tools Services business as two reportable segments: (1) U.S. Rental Tools and (2) International Rental Tools.

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

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Drilling Services Business

In our Drilling Services business, we drill oil, natural gas and geothermal 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 manage the rigs for them. The nature and scope of activities involved in drilling an oil and natural 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 Gulf of Mexico (GOM) barge drilling rig fleet, and markets our U.S. (Lower 48) Drilling-based O&M services. Our GOM barge drilling fleet operates barge rigs that drill for oil and natural gas in shallow waters in and along the inland waterways and coasts of Louisiana, Alabama and Texas. The majority of these wells are drilled in shallow water depths ranging from 6 to 12 feet. Our rigs are suitable for a variety of drilling programs, from inland coastal waters requiring shallow draft barges, to open water drilling on both state and federal water projects requiring more robust capabilities. The barge drilling industry in the GOM is characterized by cyclical activity where utilization and dayrates are typically driven by oil and natural gas prices and our customers’ access to project financing. Contract terms typically consist of well-to-well and multi-well programs, most commonly ranging from 20 to 180 days.

International & Alaska Drilling

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

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

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

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

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

Rental Tools Services Business

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

U.S. Rental Tools

Our U.S. Rental Tools segment is headquartered in New Iberia, Louisiana. We maintain an inventory of rental tools for deepwater, drilling, completion, workover, and production applications at facilities in Louisiana, Texas, Oklahoma, Wyoming, North Dakota and West Virginia.

Our largest single market for rental tools is U.S. land drilling, a cyclical market driven primarily by oil and natural gas prices and our customers' access to project financing. A portion of our U.S. rental tools business is supplying tubular goods and other equipment to offshore GOM customers.

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International Rental Tools

Our International Rental Tools segment is headquartered in Dubai, United Arab Emirates. We maintain an inventory of rental tools and provide well construction, well intervention, and surface and tubular services to our customers in the Middle East, Latin America, United Kingdom, Europe, and Asia-Pacific regions.

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

	Three Months Ended   June 30,								Six Months Ended   June 30,
Dollars in thousands	2017				2016				2017				2016
Revenues: (1)
Drilling Services:
U.S. (Lower 48) Drilling	$	5,042			$	1,065			$	6,257			$	3,150
International & Alaska Drilling	60,669				71,926				123,881				160,545
Total Drilling Services	65,711				72,991				130,138				163,695
Rental Tools Services:
U.S. Rental Tools	29,704				17,961				49,936				40,516
International Rental Tools	14,192				14,335				27,804				31,579
Total Rental Tools Services	43,896				32,296				77,740				72,095
Total revenues	109,607				105,287				207,878				235,790
Operating gross margin: (2)
Drilling Services:
U.S. (Lower 48) Drilling	(4,528		)		(9,011		)		(11,761		)		(17,571		)
International & Alaska Drilling	(2,788		)		3,196				(4,555		)		8,274
Total Drilling Services	(7,316		)		(5,815		)		(16,316		)		(9,297		)
Rental Tools Services:
U.S. Rental Tools	2,988				(5,472		)		(798		)		(9,422		)
International Rental Tools	(6,688		)		(8,938		)		(13,647		)		(14,934		)
Total Rental Tools Services	(3,700		)		(14,410		)		(14,445		)		(24,356		)
Total operating gross margin	(11,016		)		(20,225		)		(30,761		)		(33,653		)
General and administrative expense	(6,503		)		(7,995		)		(13,543		)		(17,776		)
Gain (loss) on disposition of assets, net	(113		)		(2		)		(465		)		(62		)
Total operating income (loss)	(17,632		)		(28,222		)		(44,769		)		(51,491		)
Interest expense	(11,095		)		(12,187		)		(21,965		)		(23,749		)
Interest income	22				32				32				39
Other income (loss)	560				(358		)		1,090				2,127
Income (loss) from continuing operations before income taxes	$	(28,145	)		$	(40,735	)		$	(65,612	)		$	(73,074	)

 

(1)For the six months ended June 30, 2017, our largest customer, ENL, constituted approximately 34.0 percent of our total consolidated revenues and approximately 57.0 percent of our International & Alaska Drilling segment revenues. Excluding reimbursable revenues of $27.0 million, ENL constituted approximately 24.6 percent of our total consolidated revenues and approximately 46.7 percent of our International & Alaska Drilling segment revenues. Our second largest customer, BP, constituted 10.5 percent of our total consolidated revenues and approximately 17.6 percent of our International & Alaska Drilling segment revenues.

For the six months ended June 30, 2016, our largest customer, ENL, constituted approximately 39.8 percent of our total consolidated revenues and approximately 58.4 percent of our International & Alaska Drilling segment revenues. Excluding reimbursable revenues of $36.9 million, ENL constituted approximately 28.7 percent of our total consolidated revenues and approximately 46.4 percent of our International & Alaska Drilling segment revenues.

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

Note 7 - Accounting for Uncertainty in Income Taxes

We apply the accounting guidance related to accounting for uncertainty in income taxes. This guidance prescribes a recognition threshold and a measurement attribute for the financial statement recognition and measurement of tax positions taken or expected to be taken in a tax return. For those benefits to be recognized, a tax position must be more likely than not to be sustained upon examination by taxing authorities. At June 30, 2017, we had a liability for unrecognized tax benefits of $5.2 million, primarily related to foreign operations, $4.7 million of which would favorably impact our effective tax rate upon recognition. At December 31, 2016, we had a liability for unrecognized tax benefits of $4.6 million, all of which would favorably impact our effective tax rate upon recognition, and for which no payments were made in 2016. In addition, we recognize interest and penalties that could be applied to uncertain tax positions in periodic income tax expense. As of June 30, 2017 and December 31, 2016, we had approximately $2.1 million and $1.9 million, respectively, of accrued interest and penalties related to uncertain tax positions.

Note 8 - Income Tax Expense (Benefit)

During the second quarter of 2017, we had income tax expense of $1.7 million compared with income tax benefit of $0.9 million during the second quarter of 2016. Despite the pre-tax loss for the second quarter of 2017, we recognized income tax expense due to the jurisdictional mix of income and loss during the quarter, along with our continued inability to recognize the benefits associated with certain losses as a result of valuation allowances.

Note 9 - Long-Term Debt

The following table illustrates the Company’s current debt portfolio as of June 30, 2017 and December 31, 2016:

Dollars in thousands	June 30, 2017				December 31, 2016
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	(7,867		)		(8,674		)
Total long-term debt	$	577,133			$	576,326

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 July 2022 (6.75% Notes) pursuant to an Indenture between the Company and The Bank of New York Mellon Trust Company, N.A., as trustee. The 6.75% Notes are general unsecured obligations of the Company and rank equal in right of payment with all of our existing and future senior unsecured indebtedness. The 6.75% Notes are jointly and severally guaranteed by all of our subsidiaries that guarantee indebtedness under the Second Amended and Restated Senior Secured Credit Agreement, as amended from time-to-time (2015 Secured Credit Agreement) and our 7.50% Senior Notes, due August 2020 (7.50% Notes, and collectively with the 6.75% Notes, the Senior Notes). Interest on the 6.75% Notes is payable on January 15 and July 15 of each year, beginning July 15, 2014. Debt issuance costs related to the 6.75% Notes of approximately $7.6 million ($5.0 million net of amortization as of June 30, 2017) are being amortized over the term of the notes using the effective interest rate method.

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 limits 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. 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 ($2.8 million, net of amortization as of June 30, 2017) are being amortized over the term of the notes using the effective interest rate method.

We may redeem all or a part of the 7.50% Notes upon appropriate notice, at redemption prices decreasing each year after August 1, 2016 to par beginning August 1, 2018. As of June 30, 2017, the redemption price is 103.75 percent and we have not made any redemptions to date. 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 limits 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. The 2015 Secured Credit Agreement was originally comprised of a $200.0 million revolving credit facility (Revolver) set to mature on January 26, 2020. Four amendments to the 2015 Secured Credit Agreement have been executed, which have, among other things, reduced the size of the revolver to $100 million, suspended the Leverage Ratio, Consolidated Interest Coverage Ratio, Senior Secured Leverage Ratio, and Asset Coverage Ratio covenants during specific time periods, increased the Applicable Rate for certain higher levels of consolidated leverage to a maximum of 4.00 percent per annum for Eurodollar Rate loans and to a maximum of 3.00 percent per annum for Base Rate loans, established anti-hoarding language restricting our ability to retain more than $50 million in U.S. bank accounts when there are outstanding borrowings under the Revolver, and established a $75 million Junior Lien Debt capacity.

The maximum permitted Senior Secured Leverage Ratio was 2.20:1.00 for the fiscal quarter ending June 30, 2017, decreases to 1.75:1.00 in the third quarter of 2017, and to 1.50:1.00 in the fourth quarter of 2017 and remains at 1.50:1.00 thereafter. The Asset Coverage Ratio covenant, currently at 1.10:1.00, increases to 1.25: 1.00 in the fourth quarter of 2017 and remains at 1.25:1.00 thereafter. The Consolidated Interest Coverage Ratio covenant will be reinstated in the fourth quarter of 2017 with the ratio established at 1.00:1.00, which increases by 0.25 each subsequent quarter until reaching 2.00:1.00 in the fourth quarter of 2018, and remains at 2.00:1.00 thereafter. The Leverage Ratio covenant will be reinstated in the fourth quarter of 2018 with the ratio established at 4.25:1.00.

On February 21, 2017, we executed the fourth amendment to the 2015 Secured Credit Agreement (the Fourth Amendment) which, among other things, permits the sale and issuance of certain equity interests of the Company, including the Convertible Preferred Stock, and permits the Company to pay dividends on the Convertible Preferred Stock, up to certain aggregate amounts specified therein. The debt issuance costs incurred relating to the Fourth Amendment were nominal. Debt issuance costs remaining as of June 30, 2017 were $1.0 million which are being amortized through January 2020 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. As of June 30, 2017, we were in compliance with all covenants contained in the 2015 Secured Credit Agreement though our ability to access the full $100 million of the Revolver was restricted to $82.3 million due to $5.8 million in letters of credit outstanding and $11.9 million related to a cap imposed by our Senior Secured Leverage Ratio covenant calculation.

Our Revolver is available for general corporate purposes and to support letters of credit. Interest on Revolver loans accrues at a Base Rate plus an Applicable Rate or LIBOR plus an Applicable Rate. Revolving loans are available subject to a quarterly asset coverage ratio calculation based on the Orderly Liquidation Value of certain specified rigs including barge rigs in the GOM and land rigs in Alaska, and certain U.S.-based rental equipment of the Company and its subsidiary guarantors and a percentage

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of eligible domestic accounts receivable. Letters of credit outstanding against the Revolver as of June 30, 2017 totaled $5.8 million. There were no amounts drawn on the Revolver as of June 30, 2017.    

Note 10 - Fair Value of Financial Instruments

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

The fair value measurement and disclosure requirements of FASB ASC Topic No. 820, Fair Value Measurement and Disclosures 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.

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:     

	June 30, 2017								December 31, 2016
Dollars in thousands	Carrying Amount				Fair Value				Carrying Amount				Fair Value
Long-term debt
6.75% Notes	$	360,000			$	274,500			$	360,000			$	311,400
7.50% Notes	225,000				196,313				225,000				201,375
Total principal	$	585,000			$	470,813			$	585,000			$	512,775

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 six months ended June 30, 2017.  

Note 11 - Commitments and Contingencies

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

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Note 12 - Recent Accounting Pronouncements    

In January 2017, the FASB issued Accounting Standards Update (ASU) No. 2017-04, Intangibles-Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment. The standard simplifies the subsequent measurement of goodwill by eliminating the second step of the goodwill impairment test. This standard is effective for annual or interim goodwill impairment tests in fiscal years beginning after December 15, 2019. Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. Effective January 1, 2017, we adopted ASU 2017-04 and it did not have a material impact on our consolidated statements of financial position, results of operations, cash flows, and on the disclosures contained in our notes to the consolidated financial statements.

In October 2016, the FASB issued ASU No. 2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other than Inventory. The ASU requires entities to recognize at the transaction date the income tax consequences of intercompany asset transfers other than inventory. The standard becomes effective for public companies for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. Early adoption is permitted, but only at the beginning of the annual period for which no financial statements have been issued or been made available for issuance. Effective January 1, 2017, we adopted ASU 2016-16 prospectively and it did not have a material impact on our consolidated statements of financial position, results of operations and cash flows.

In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments. The ASU is intended to reduce diversity in current practice regarding the manner in which certain cash receipts and cash payments are presented and classified in the cash flow statement. The standard becomes effective for public companies for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. Early adoption is permitted. Effective January 1, 2017, we adopted ASU 2016-15 retrospectively and it did not have a material impact on our statement of cash flows.

In March 2016, the FASB issued ASU No. 2016-09, Compensation - Stock Compensation (Topic 718).  The objective of this update is to simplify several aspects of accounting for share-based payment transactions, including income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows.  The standard became effective for public companies for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years.  Effective January 1, 2017, we adopted ASU 2016-09. The adoption did not have a material impact on our consolidated statements of financial position, results of operations or cash flows. In accordance with the ASU requirements, we adopted certain aspects of the ASU as follows:

•

Accounting for excess tax benefits and certain tax deficiencies - The guidance requires all excess tax benefits, and certain tax deficiencies to be recorded through the income statement instead of additional paid in capital, where the activity was historically recorded. We adopted this change prospectively.  There is no cumulative effect of the adoption as we have no unrecognized excess tax benefits or minimum withholding requirements that impact the income statement and, accordingly, prior periods have not been adjusted.

•

Cash flow presentation of excess tax benefits and certain tax deficiencies - We adopted this change retrospectively. Tax related cash flows from share based payments are to be presented as operating activities in the statement of cash flows. Consequently, activity of $1.6 million for the six month period ended June 30, 2016, recorded through equity, has been reclassified from financing activities to operating activities in the statement of cash flows.

•	Accounting for forfeitures - We have made an entity-wide accounting policy election to continue to estimate forfeitures and adjust the estimate when it is likely to change. This election does not change our current policy and, accordingly, there is no impact on our consolidated statements of financial position, results of operations or cash flows.

•	Cash paid to a tax authority when shares are withheld to satisfy the employer’s statutory income tax withholding obligation - We adopted this change retrospectively. The activity is now required to be presented as financing activities in the statement of cash flows. For the six-month period ended June 30, 2016, we have reclassified $0.8 million from operating activities to financing activities.

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In March 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842). Effective no later than January 1, 2019, we will adopt this accounting standards update that (a) requires lessees to recognize a right to use asset and a lease liability for virtually all leases, and (b) updates previous accounting standards for lessors to align certain requirements with the updates to lessee accounting standards and the revenue recognition accounting standards. The standard is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, although early adoption is permitted. This update establishes a new lease accounting model for lessees. Upon adoption, a modified retrospective approach is required for leases that exist, or are entered into, after the beginning of the earliest comparative period presented. Under the updated accounting standard, we have determined that our drilling contracts may contain a lease component; therefore, our adoption of the standard could require that we separately recognize revenues associated with the lease and service components. Given the interaction between this update and the accounting standards update to revenue contracts with customers, we expect to adopt the updates concurrently, effective January 1, 2018, and we expect to apply the modified retrospective approach. Our adoption, and the ultimate effect on our consolidated financial statements, will be based on an evaluation of the contract-specific facts and circumstances, and such effect could introduce variability to the timing of our revenue recognition relative to current accounting standards. We are evaluating the requirements to determine the effect such requirements may have on our consolidated statements of financial position, results of operations, cash flows and on the disclosures contained in our notes to the consolidated financial statements upon the adoption of ASU 2016-02. Depending on the results of the evaluation our ultimate conclusions may vary.    

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606). This ASU supersedes the revenue recognition requirements in ASC 605 - Revenue Recognition and most industry-specific guidance throughout the Codification. The standard requires that an entity recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services and should be applied retrospectively to each prior reporting period presented or retrospectively with the cumulative effect of initially applying the ASU recognized at the date of initial application. ASU 2014-09 is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. At this time we expect to apply the modified retrospective approach; however, we are evaluating the requirements to determine the effect such requirements may have on our consolidated statements of financial position, results of operations, cash flows and on the disclosures contained in our notes to the consolidated financial statements upon the adoption of ASU 2014-09. Depending on the results of the evaluation our ultimate conclusions may vary.            

In August 2014, the FASB issued ASU No. 2014-15, Presentation of Financial Statements - Going Concern (Subtopic 205-40). The objective of this update is to provide guidance about management's responsibility to evaluate whether there is substantial doubt about an entity's ability to continue as a going concern and provide footnote disclosures. The amendments in this update become effective for public companies for the annual period after December 15, 2016, and for annual periods and interim periods thereafter. Early application is permitted. Effective January 1, 2017, we adopted ASU 2014-15 prospectively and it did not have a material impact on our consolidated statements of financial position, results of operations, cash flows, and on the disclosures contained in our notes to the consolidated financial statements.

20

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

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

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

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

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

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

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

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

We are providing unaudited consolidating condensed financial information of the parent, Parker Drilling, the guarantor subsidiaries, and the non-guarantor subsidiaries as of June 30, 2017 and December 31, 2016 and for the six months ended June 30, 2017 and 2016, respectively. The consolidating condensed financial statements present investments in both consolidated and unconsolidated subsidiaries using the equity method of accounting.

21

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PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATING CONDENSED BALANCE SHEET

(Dollars in Thousands)

(Unaudited)

 

	June 30, 2017
	Parent				Guarantor				Non-Guarantor				Eliminations				Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	89,006			$	16,558			$	40,670			$	—			$	146,234
Accounts and notes receivable, net	—				29,544				90,526				—				120,070
Rig materials and supplies	—				(4,813		)		40,083				—				35,270
Other current assets	—				8,723				16,985				—				25,708
Total current assets	89,006				50,012				188,264				—				327,282
Property, plant and equipment, net	(19		)		454,594				212,467				—				667,042
Goodwill	—				6,708				—				—				6,708
Intangible assets, net	—				8,281				189				—				8,470
Investment in subsidiaries and intercompany advances	2,950,669				2,947,916				3,804,358				(9,702,943		)		—
Other noncurrent assets	(168,681		)		222,237				539,876				(480,828		)		112,604
Total assets	$	2,870,975			$	3,689,748			$	4,745,154			$	(10,183,771	)		$	1,122,106
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	(47,834	)		$	190,474			$	581,140			$	(617,477	)		$	106,303
Accrued income taxes	69,506				(49,988		)		(14,382		)		—				5,136
Total current liabilities	21,672				140,486				566,758				(617,477		)		111,439
Long-term debt, net	577,133				—				—				—				577,133
Other long-term liabilities	2,867				5,779				3,872				—				12,518
Deferred tax liability	77,221				—				—				—				77,221
Intercompany payables	1,846,121				1,452,085				2,281,438				(5,579,644		)		—
Total liabilities	2,525,014				1,598,350				2,852,068				(6,197,121		)		778,311
Total equity	345,961				2,091,398				1,893,086				(3,986,650		)		343,795
Total liabilities and stockholders’ equity	$	2,870,975			$	3,689,748			$	4,745,154			$	(10,183,771	)		$	1,122,106

22

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PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATING CONDENSED BALANCE SHEET

(Dollars in Thousands)

(Unaudited)

 

	December 31, 2016
	Parent				Guarantor				Non-Guarantor				Eliminations				Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	65,000			$	14,365			$	40,326			$	—			$	119,691
Accounts and notes receivable, net	—				15,749				97,482				—				113,231
Rig materials and supplies	—				(5,369		)		37,723				—				32,354
Other current assets	(50,296		)		41,304				30,034				—				21,042
Total current assets	14,704				66,049				205,565				—				286,318
Property, plant and equipment, net	(19		)		469,927				223,531				—				693,439
Goodwill	—				6,708				—				—				6,708
Intangible assets, net	—				9,434				494				—				9,928
Investment in subsidiaries and intercompany advances	2,979,413				2,932,375				3,676,402				(9,588,190		)		—
Other noncurrent assets	(253,679		)		301,771				539,877				(480,811		)		107,158
Total assets	$	2,740,419			$	3,786,264			$	4,645,869			$	(10,069,001	)		$	1,103,551
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	(10,080	)		$	149,210			$	577,188			$	(617,477	)		$	98,841
Accrued income taxes	—				1,576				2,504				—				4,080
Total current liabilities	(10,080		)		150,786				579,692				(617,477		)		102,921
Long-term debt, net	576,326				—				—				—				576,326
Other long-term liabilities	2,867				9,338				3,631				—				15,836
Deferred tax liability	(28		)		73,039				(3,678		)		—				69,333
Intercompany payables	1,828,317				1,437,417				2,161,864				(5,427,598		)		—
Total liabilities	2,397,402				1,670,580				2,741,509				(6,045,075		)		764,416
Total equity	343,017				2,115,684				1,904,360				(4,023,926		)		339,135
Total liabilities and stockholders’ equity	$	2,740,419			$	3,786,264			$	4,645,869			$	(10,069,001	)		$	1,103,551

23

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PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATING CONDENSED STATEMENT OF OPERATIONS

(Dollars in Thousands)

(Unaudited)

	Three Months Ended June 30, 2017
	Parent				Guarantor				Non-Guarantor				Eliminations				Consolidated
Total revenues	$	—			$	41,490			$	85,028			$	(16,911	)		$	109,607
Operating expenses	—				25,327				81,225				(16,911		)		89,641
Depreciation and amortization	—				20,270				10,712				—				30,982
Total operating gross margin (loss)	—				(4,107		)		(6,909		)		—				(11,016		)
General and administrative expense (1)	(69		)		(6,303		)		(131		)		—				(6,503		)
Gain (loss) on disposition of assets, net	—				(26		)		(87		)		—				(113		)
Total operating income (loss)	(69		)		(10,436		)		(7,127		)		—				(17,632		)
Other income (expense):
Interest expense	(11,809		)		(41		)		(2,070		)		2,825				(11,095		)
Interest income	184				179				2,484				(2,825		)		22
Other	—				15				545				—				560
Equity in net earnings of subsidiaries	(15,823		)		—				—				15,823				—
Total other income (expense)	(27,448		)		153				959				15,823				(10,513		)
Income (loss) before income taxes	(27,517		)		(10,283		)		(6,168		)		15,823				(28,145		)
Total income tax expense (benefit)	2,371				(1,585		)		957				—				1,743
Net income (loss)	$	(29,888	)		$	(8,698	)		$	(7,125	)		$	15,823			$	(29,888	)
Less: Mandatory convertible preferred stock dividend	$	1,239			$	—			$	—			$	—			$	1,239
Net income (loss) available to common stockholders	$	(31,127	)		$	(8,698	)		$	(7,125	)		$	15,823			$	(31,127	)

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

24

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PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATING CONDENSED STATEMENT OF OPERATIONS

(Dollars in Thousands)

(Unaudited)

	Three Months Ended June 30, 2016
	Parent				Guarantor				Non-Guarantor				Eliminations				Consolidated
Total revenues	$	—			$	34,586			$	88,895			$	(18,194	)		$	105,287
Operating expenses	—				25,577				81,812				(18,194		)		89,195
Depreciation and amortization	—				23,314				13,003				—				36,317
Total operating gross margin (loss)	—				(14,305		)		(5,920		)		—				(20,225		)
General and administrative expense (1)	(113		)		(7,828		)		(54		)		—				(7,995		)
Gain (loss) on disposition of assets, net	—				209				(211		)		—				(2		)
Total operating income (loss)	(113		)		(21,924		)		(6,185		)		—				(28,222		)
Other income (expense):
Interest expense	(12,896		)		(44		)		(2,290		)		3,043				(12,187		)
Interest income	191				180				2,704				(3,043		)		32
Other	—				(11		)		(347		)		—				(358		)
Equity in net earnings of subsidiaries	(24,568		)		—				—				24,568				—
Total other income (expense)	(37,273		)		125				67				24,568				(12,513		)
Income (loss) before income taxes	(37,386		)		(21,799		)		(6,118		)		24,568				(40,735		)
Income tax expense (benefit)	2,438				(5,297		)		1,946				—				(913		)
Net income (loss)	(39,824		)		(16,502		)		(8,064		)		24,568				(39,822		)

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

25

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PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATING CONDENSED STATEMENT OF OPERATIONS

(Dollars in Thousands)

(Unaudited)

	Six Months Ended June 30, 2017
	Parent				Guarantor				Non-Guarantor				Eliminations				Consolidated
Total revenues	$	—			$	69,383			$	173,265			$	(34,770	)		$	207,878
Operating expenses	—				46,277				163,948				(34,770		)		175,455
Depreciation and amortization	—				41,458				21,726				—				63,184
Total operating gross margin (loss)	—				(18,352		)		(12,409		)		—				(30,761		)
General and administrative expense (1)	(147		)		(13,173		)		(223		)		—				(13,543		)
Gain (loss) on disposition of assets, net	—				(242		)		(223		)		—				(465		)
Total operating income (loss)	(147		)		(31,767		)		(12,855		)		—				(44,769		)
Other income (expense):
Interest expense	(23,478		)		(85		)		(4,013		)		5,611				(21,965		)
Interest income	332				357				4,954				(5,611		)		32
Other	—				47				1,043				—				1,090
Equity in net earnings of subsidiaries	(37,602		)		—				—				37,602				—
Total other income (expense)	(60,748		)		319				1,984				37,602				(20,843		)
Income (loss) before income taxes	(60,895		)		(31,448		)		(10,871		)		37,602				(65,612		)
Total income tax expense (benefit)	8,801				(7,161		)		2,445				—				4,085
Net income (loss)	(69,696		)		(24,287		)		(13,316		)		37,602				(69,697		)
Less: Mandatory convertible preferred stock dividend	1,239				—				—				—				1,239
Net income (loss) available to common stockholders	$	(70,935	)		$	(24,287	)		$	(13,316	)		$	37,602			$	(70,936	)

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

26

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PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATING CONDENSED STATEMENT OF OPERATIONS

(Dollars in Thousands)

(Unaudited)

	Six Months Ended June 30, 2016
	Parent				Guarantor				Non-Guarantor				Eliminations				Consolidated
Total revenues	$	—			$	81,968			$	195,372			$	(41,550	)		$	235,790
Operating expenses	—				58,413				180,449				(41,550		)		197,312
Depreciation and amortization	—				46,439				25,692				—				72,131
Total operating gross margin (loss)	—				(22,884		)		(10,769		)		—				(33,653		)
General and administrative expense (1)	(200		)		(17,440		)		(136		)		—				(17,776		)
Gain (loss) on disposition of assets, net	—				153				(215		)		—				(62		)
Total operating income (loss)	(200		)		(40,171		)		(11,120		)		—				(51,491		)
Other income (expense):
Interest expense	(24,752		)		(481		)		(5,150		)		6,634				(23,749		)
Interest income	395				359				5,919				(6,634		)		39
Other	—				473				1,654				—				2,127
Equity in net earnings of subsidiaries	(40,793		)		—				—				40,793				—
Total other income (expense)	(65,150		)		351				2,423				40,793				(21,583		)
Income (loss) before income taxes	(65,350		)		(39,820		)		(8,697		)		40,793				(73,074		)
Income tax expense (benefit)	70,307				(9,004		)		1,280				—				62,583
Net income (loss)	(135,657		)		(30,816		)		(9,977		)		40,793				(135,657		)

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

27

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PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATING CONDENSED STATEMENT OF COMPREHENSIVE INCOME (LOSS)

(Dollars in Thousands)

(Unaudited)

	Three Months Ended June 30, 2017
	Parent				Guarantor				Non-Guarantor				Eliminations				Consolidated
Comprehensive income (loss):
Net income (loss)	$	(29,888	)		$	(8,698	)		$	(7,125	)		$	15,823			$	(29,888	)
Other comprehensive income (loss), net of tax:
Currency translation difference on related borrowings	—				—				185				—				185
Currency translation difference on foreign currency net investments	—				—				686				—				686
Total other comprehensive income (loss), net of tax:	—				—				871				—				871
Comprehensive income (loss)	$	(29,888	)		$	(8,698	)		$	(6,254	)		$	15,823			$	(29,017	)

PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATING CONDENSED STATEMENT OF COMPREHENSIVE INCOME (LOSS)

(Dollars in Thousands)

(Unaudited)

	Three Months Ended June 30, 2016
	Parent				Guarantor				Non-Guarantor				Eliminations				Consolidated
Comprehensive income (loss):
Net income (loss)	$	(39,824	)		$	(16,502	)		$	(8,064	)		$	24,568			$	(39,822	)
Other comprehensive income (loss), net of tax:
Currency translation difference on related borrowings	—				—				(307		)		—				(307		)
Currency translation difference on foreign currency net investments	—				—				(2,228		)		—				(2,228		)
Total other comprehensive income (loss), net of tax:	—				—				(2,535		)		—				(2,535		)
Comprehensive income (loss)	(39,824		)		(16,502		)		(10,599		)		24,568				(42,357		)

28

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PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATING CONDENSED STATEMENT OF COMPREHENSIVE INCOME (LOSS)

(Dollars in Thousands)

(Unaudited)

	Six Months Ended June 30, 2017
	Parent				Guarantor				Non-Guarantor				Eliminations				Consolidated
Comprehensive income (loss):
Net income (loss)	$	(69,696	)		$	(24,287	)		$	(13,316	)		$	37,602			$	(69,697	)
Other comprehensive income (loss), net of tax:
Currency translation difference on related borrowings	—				—				268				—				268
Currency translation difference on foreign currency net investments	—				—				1,449				—				1,449
Total other comprehensive income (loss), net of tax:	—				—				1,717				—				1,717
Comprehensive income (loss)	$	(69,696	)		$	(24,287	)		$	(11,599	)		$	37,602			$	(67,980	)

PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATING CONDENSED STATEMENT OF COMPREHENSIVE INCOME (LOSS)

(Dollars in Thousands)

(Unaudited)

	Six Months Ended June 30, 2016
	Parent				Guarantor				Non-Guarantor				Eliminations				Consolidated
Comprehensive income (loss):
Net income (loss)	$	(135,657	)		$	(30,816	)		$	(9,977	)		$	40,793			$	(135,657	)
Other comprehensive income (loss), net of tax:
Currency translation difference on related borrowings	—				—				195				—				195
Currency translation difference on foreign currency net investments	—				—				(3,766		)		—				(3,766		)
Total other comprehensive income (loss), net of tax:	—				—				(3,571		)		—				(3,571		)
Comprehensive income (loss)	(135,657		)		(30,816		)		(13,548		)		40,793				(139,228		)

29

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PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)

(Unaudited)

                    

	Six Months Ended June 30, 2017
	Parent				Guarantor				Non-Guarantor				Eliminations				Consolidated
Cash flows from operating activities:
Net income (loss)	$	(69,696	)		$	(24,287	)		$	(13,316	)		$	37,602			$	(69,697	)
Adjustments to reconcile net income (loss):
Depreciation and amortization	—				41,458				21,726				—				63,184
(Gain) loss on disposition of assets	—				242				223				—				465
Deferred income tax expense (benefit)	(10,359		)		8,943				482				—				(934		)
Expenses not requiring cash	3,154				120				1,674				—				4,948
Equity in net earnings of subsidiaries	37,602				—				—				(37,602		)		—
Change in assets and liabilities:
Accounts and notes receivable	—				(13,787		)		6,934				—				(6,853		)
Other assets	(50,315		)		32,013				16,580				—				(1,722		)
Accounts payable and accrued liabilities	(37,753		)		29,831				(313		)		—				(8,235		)
Accrued income taxes	71,942				(54,000		)		(16,666		)		—				1,276
Net cash provided by (used in) operating activities	(55,425		)		20,533				17,324				—				(17,568		)
Cash flows from investing activities:
Capital expenditures	—				(18,726		)		(7,833		)		—				(26,559		)
Proceeds from the sale of assets	—				25				160				—				185
Net cash provided by (used in) investing activities	—				(18,701		)		(7,673		)		—				(26,374		)
Cash flows from financing activities:
Proceeds from the issuance of common stock	25,200				—				—				—				25,200
Proceeds from the issuance of mandatory convertible preferred stock	50,000				—				—				—				50,000
Payment of equity issuance costs	(2,864		)		—				—				—				(2,864		)
Mandatory convertible preferred stock dividend	(1,239		)		—				—				—				(1,239		)
Shares surrendered in lieu of tax	(612		)		—				—				—				(612		)
Intercompany advances, net	8,946				361				(9,307		)		—				—
Net cash provided by (used in) financing activities	79,431				361				(9,307		)		—				70,485
Net increase (decrease) in cash and cash equivalents	24,006				2,193				344				—				26,543
Cash and cash equivalents, beginning of year	65,000				14,365				40,326				—				119,691
Cash and cash equivalents, end of period	$	89,006			$	16,558			$	40,670			$	—			$	146,234

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PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)

(Unaudited)

	Six Months Ended June 30, 2016
	Parent				Guarantor				Non-Guarantor				Eliminations				Consolidated
Cash flows from operating activities:
Net income (loss)	$	(135,657	)		$	(30,816	)		$	(9,977	)		$	40,793			$	(135,657	)
Adjustments to reconcile net income (loss)
Depreciation and amortization	—				46,439				25,692				—				72,131
Accretion of contingent consideration	—				419				—				—				419
(Gain) loss on debt modification	1,088				—				—				—				1,088
(Gain) loss on disposition of assets	—				(153		)		215				—				62
Deferred income tax expense (benefit)	49,167				9,569				569				—				59,305
Excess tax benefit (expense) from stock-based compensation	(1,617		)		—				—				—				(1,617		)
Expenses not requiring cash	3,510				(282		)		(7,637		)		—				(4,409		)
Equity in net earnings of subsidiaries	40,793				—				—				(40,793		)		—
Change in assets and liabilities:
Accounts and notes receivable	—				7,755				14,564				—				22,319
Other assets	(103,035		)		102,496				(2,453		)		—				(2,992		)
Accounts payable and accrued liabilities	3,281				(5,737		)		(4,406		)		—				(6,862		)
Accrued income taxes	21,711				(17,830		)		(7,866		)		—				(3,985		)
Net cash provided by (used in) operating activities	(120,759		)		111,860				8,701				—				(198		)
Cash flows from investing activities:
Capital expenditures	—				(7,499		)		(8,758		)		—				(16,257		)
Proceeds from the sale of assets	—				121				1,266				—				1,387
Net cash provided by (used in) investing activities	—				(7,378		)		(7,492		)		—				(14,870		)
Cash flows from financing activities:
Payment for noncontrolling interest	(3,375		)		—				—				—				(3,375		)
Payment of contingent consideration	—				(6,000		)		—				—				(6,000		)
Shares surrendered in lieu of tax	(817		)		—				—				—				(817		)
Intercompany advances, net	106,246				(100,144		)		(6,102		)		—				—
Net cash provided by (used in) financing activities	102,054				(106,144		)		(6,102		)		—				(10,192		)
Net increase (decrease) in cash and cash equivalents	(18,705		)		(1,662		)		(4,893		)		—				(25,260		)
Cash and cash equivalents, beginning of year	73,985				13,854				46,455				—				134,294
Cash and cash equivalents, end of period	$	55,280			$	12,192			$	41,562			$	—			$	109,034

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

Management’s discussion and analysis should be read in conjunction with Item 1. Financial Statements of this quarterly report on Form 10-Q and with our Annual Report on Form 10-K for the year ended December 31, 2016 (2016 Form 10-K).

Executive Summary

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

Historical market indicators are listed below:

		Six Months Ended June 30,
		2017				2016			% Change
Worldwide Rig Count (1)
U.S. (land and offshore)		816				488			67	%
International (2)		948				979			(3	)%
Commodity Prices (3)
Crude Oil (United Kingdom Brent)		$	52.68			41.21			28	%
Crude Oil (West Texas Intermediate)		$	49.95			39.78			26	%
Natural Gas (Henry Hub)		$	3.10			2.12			46	%

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

(2) Excludes Canadian Rig Count.

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

Financial Results

Our revenues for the 2017 second quarter increased 4.1 percent to $109.6 million from $105.3 million for the 2016 second quarter. Operating gross margin increased $9.2 million to a loss of $11.0 million for the three months ended June 30, 2017 compared with a loss of $20.2 million for the three months ended June 30, 2016. The second quarter of 2017 was, for the most part, a continuation of many of the trends we saw during the first quarter of 2017. While the overall market for oilfield services remains challenging and pricing is still unfavorable, current activity levels, particularly within U.S. markets, continue to support improvements in business results.

Comparing our 2017 second quarter results with our 2016 second quarter results, the largest contributor to our revenue and operating margin increases was our U.S. Rental Tools segment, where revenues increased 65.0 percent and operating gross margin excluding depreciation and amortization increased 140.4 percent. The increases were primarily driven by higher U.S. land rentals associated with improved customer activity. Our U.S. (Lower 48) Drilling segment revenues also increased meaningfully as utilization increased in the 2017 second quarter compared with the 2016 second quarter. This segment’s operating gross margin excluding depreciation and amortization increased 74.4 percent as it benefited from the increase in revenues and continued impact of cost savings initiatives. Our International & Alaska Drilling segment experienced a 15.6 percent decline in revenues and a 47.8 percent decline in operating gross margins excluding depreciation and amortization. These decreases were driven primarily by a reduction in project services activities and a decline in utilization. Finally, while our International Rental Tools segment revenues were down less than one percent, for the 2017 second quarter compared with the 2016 second quarter, operating gross margin excluding depreciation and amortization increased 42.9 percent as the segment continued to benefit from the impact of organizational efficiency initiatives.

Outlook

Looking forward, we continue to believe that industry conditions are gradually improving, despite recent oil price volatility. We believe that by continuing our operational and financial discipline, we are well-positioned to benefit from an increase in activity while also remaining responsive to any possible retrenchment in activity. For the third quarter, we expect consolidated revenues and gross margin to increase compared to the 2017 second quarter, as we anticipate increases in activity in several markets in which we operate.

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In our U.S. (Lower 48) Drilling segment, for the 2017 third quarter we expect utilization to maintain similar levels with the 2017 second quarter. For our International & Alaska Drilling segment, we believe activity has stabilized and third quarter revenues and gross margin should remain in line with the second quarter. We expect to see some improvement in the fourth quarter of 2017 as we begin operations under new contracts awarded in the second quarter of 2017.

In our U.S. Rental Tools segment, we expect further improvement in U.S. land activity, which should continue to lift revenues and gross margin. We also anticipate some benefit from an expected increase in deep water rental volumes. For our International Rental Tools segment, we expect revenues and gross margin to improve in the 2017 third quarter due to increased activity in the Middle East and Latin America.

Results of Operations

Our business is comprised of two business lines: (1) Drilling Services and (2) Rental Tools Services. We report our Drilling Services business as two reportable segments: (1) U.S. (Lower 48) Drilling and (2) International & Alaska Drilling. We report our Rental Tools Services business as two reportable segments: (1) U.S. Rental Tools and (2) International Rental Tools. We eliminate inter-segment revenues and expenses.

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

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

Revenues increased $4.3 million, or 4.1 percent, to $109.6 million for the three months ended June 30, 2017 compared with revenues of $105.3 million for the three months ended June 30, 2016. Operating gross margin increased $9.2 million to a loss of $11.0 million for the three months ended June 30, 2017 compared with a loss of $20.2 million for the three months ended June 30, 2016.

    The following table presents our operating results for the comparable periods by reportable segment:

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	Three Months Ended June 30,
Dollars in Thousands	2017							2016
Revenues:
Drilling Services:
U.S. (Lower 48) Drilling	$	5,042			5	%		$	1,065			1	%
International & Alaska Drilling	60,669				55	%		71,926				68	%
Total Drilling Services	65,711				60	%		72,991				69	%
Rental Tools Services:
U.S. Rental Tools	29,704				27	%		17,961				17	%
International Rental Tools	14,192				13	%		14,335				14	%
Total Rental Tools Services	43,896				40	%		32,296				31	%
Total revenues	109,607				100	%		105,287				100	%
Operating gross margin (loss) excluding depreciation and amortization:
Drilling Services:
U.S. (Lower 48) Drilling	(1,025		)		(20	)%		(3,902		)		(366	)%
International & Alaska Drilling	9,265				15	%		17,816				25	%
Total Drilling Services	8,240				13	%		13,914				19	%
Rental Tools Services:
U.S. Rental Tools	13,731				46	%		5,694				32	%
International Rental Tools	(2,005		)		(14	)%		(3,516		)		(25	)%
Total Rental Tools Services	11,726				27	%		2,178				7	%
Total operating gross margin (loss) excluding depreciation and amortization	19,966				18	%		16,092				15	%
Depreciation and amortization	(30,982		)					(36,317		)
Total operating gross margin (loss)	(11,016		)					(20,225		)
General and administrative expense	(6,503		)					(7,995		)
Gain (loss) on disposition of assets, net	(113		)					(2		)
Total operating income (loss)	$	(17,632	)					$	(28,222	)

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

Dollars in Thousands	U.S. (Lower 48) Drilling				International & Alaska Drilling				U.S. Rental Tools				International Rental Tools				Total
Three Months Ended June 30, 2017
Operating gross margin (loss) (1)	$	(4,528	)		$	(2,788	)		$	2,988			$	(6,688	)		$	(11,016	)
Depreciation and amortization	3,503				12,053				10,743				4,683				30,982
Operating gross margin (loss) excluding depreciation and amortization	$	(1,025	)		$	9,265			$	13,731			$	(2,005	)		$	19,966
Three Months Ended June 30, 2016
Operating gross margin (loss) (1)	$	(9,011	)		$	3,196			$	(5,472	)		$	(8,938	)		$	(20,225	)
Depreciation and amortization	5,109				14,620				11,166				5,422				36,317
Operating gross margin (loss) excluding depreciation and amortization	$	(3,902	)		$	17,816			$	5,694			$	(3,516	)		$	16,092

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

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The following table presents our average utilization rates and rigs available for service for the three months ended June 30, 2017 and 2016, respectively:

	Three Months Ended June 30,
	2017			2016
U.S. (Lower 48) Drilling
Rigs available for service (1)	13.0			13.0
Utilization rate of rigs available for service (2)	19	%		5	%
International & Alaska Drilling
Eastern Hemisphere
Rigs available for service (1)	13.0			13.0
Utilization rate of rigs available for service (2)	31	%		38	%
Latin America Region
Rigs available for service (1)	7.0			7.0
Utilization rate of rigs available for service (2)	14	%		29	%
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			22.0
Utilization rate of rigs available for service (2)	32	%		41	%

(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.

Drilling Services Business

U.S. (Lower 48) Drilling

U.S. (Lower 48) Drilling segment revenues increased $3.9 million, to $5.0 million for the second quarter of 2017 compared with revenues of $1.1 million for the second quarter of 2016. The increase was primarily due to higher utilization. Utilization increased to 19.0 percent for the quarter ended June 30, 2017 from 5.0 percent for the quarter ended June 30, 2016.

U.S. (Lower 48) Drilling segment operating gross margin excluding depreciation and amortization improved $2.9 million, or 74.4 percent, to a loss of $1.0 million for the second quarter of 2017 compared with a loss of $3.9 million for the second quarter of 2016. The improvement was primarily due to the increase in revenues discussed above.

International & Alaska Drilling

International & Alaska Drilling segment revenues decreased $11.2 million, or 15.6 percent, to $60.7 million for the second quarter of 2017 compared with $71.9 million for the second quarter of 2016.

The decrease in revenues was primarily due to the following:

•	a decrease of $7.5 million in revenues related to our project services activities;

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•	a decrease of $3.8 million in revenues from reimbursable costs (“reimbursable revenues”), which decreased revenues but had a minimal impact on operating margins;

•	a decrease of $1.9 million in revenues earned from mobilization and demobilization activities; and

•

a decrease of $1.2 million, excluding reimbursable revenues, resulting from decreased utilization for Company-owned rigs. Utilization for the segment decreased to 32.0 percent for the quarter ended June 30, 2017 from 41.0 percent for the quarter ended June 30, 2016. The decline in utilization was primarily due to the reduction in customer activity as a result of the continued impact of the decline in oil prices.

The decreases were partially offset by an increase of $4.2 million primarily related to an increase in average revenues per day associated with our O&M activities for the Hibernia platform located off the Atlantic Coast of Canada.

International & Alaska Drilling segment operating gross margin excluding depreciation and amortization decreased $8.5 million, or 47.8 percent, to $9.3 million for the second quarter of 2017 compared with $17.8 million for the second quarter of 2016. The decrease in operating gross margin excluding depreciation and amortization was primarily due to the decrease in our project services activities discussed above as well as the impact of decreased utilization for Company-owned rigs.

Rental Tools Services Business

U.S. Rental Tools

U.S. Rental Tools segment revenues increased $11.7 million, or 65.0 percent, to $29.7 million for the second quarter of 2017 compared with $18.0 million for the second quarter of 2016. The increase was primarily driven by an increase in U.S. land rentals due to improved customer activity, partially offset by a decline in offshore GOM rental revenues.

U.S. Rental Tools segment operating gross margin excluding depreciation and amortization increased $8.0 million, or 140.4 percent, to $13.7 million for the second quarter of 2017 compared with $5.7 million for the second quarter of 2016. The increase was primarily due to the increase in revenues discussed above.

International Rental Tools

International Rental Tools segment revenues decreased $0.1 million, or 0.7 percent, to $14.2 million for the second quarter of 2017 compared with $14.3 million for the second quarter of 2016. The decrease was primarily attributable to reduced customer activity impacting offshore rental revenues, partially offset by an increase in onshore rental activity.

International Rental Tools segment operating gross margin excluding depreciation and amortization improved $1.5 million, or 42.9 percent, to a loss of $2.0 million for the second quarter of 2017 compared with a loss of $3.5 million for the second quarter of 2016. The improvement was due to lower operating costs resulting from organizational efficiency initiatives.

Other Financial Data

General and administrative expense

General and administrative expense decreased $1.5 million to $6.5 million for the second quarter of 2017 compared with $8.0 million for the second quarter of 2016 primarily due to a reduction in incentive compensation associated with the departure of the Company’s chief financial officer and reduced overhead costs resulting from organizational efficiency initiatives.

Gain (loss) on disposition of assets

Net losses recognized on asset dispositions were $0.1 million for the second quarter of 2017 compared with a nominal loss for the second quarter of 2016. We periodically sell equipment deemed to be excess, obsolete, or not currently required for operations.

Interest income and expense

Interest expense decreased $1.1 million to $11.1 million for the second quarter of 2017 compared with $12.2 million for the second quarter of 2016. The decrease in interest expense was primarily related to the write off of $1.1 million of debt issuance costs during the second quarter of 2016 in conjunction with the execution of an amendment to our revolving credit facility. Interest income during each of the 2017 and 2016 second quarters was nominal.

Other income and expense

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Other income and expense was $0.6 million of income for the second quarter of 2017 compared with $0.4 million of expense for the second quarter of 2016. Activity in both periods primarily included the impact of foreign currency fluctuations.

Income tax expense (benefit)

During the second quarter of 2017, we had income tax expense of $1.7 million compared with income tax benefit of $0.9 million during the second quarter of 2016. Despite the pre-tax loss for the second quarter of 2017, we recognized income tax expense due to the jurisdictional mix of income and loss during the period, along with our continued inability to recognize the benefits associated with certain losses as a result of valuation allowances.

Six Months Ended June 30, 2017 Compared with Six Months Ended June 30, 2016

Revenues decreased $27.9 million, or 11.8 percent, to $207.9 million for the six months ended June 30, 2017 compared with revenues of $235.8 million for the six months ended June 30, 2016. Operating gross margin increased $2.9 million to a loss of $30.8 million for the six months ended June 30, 2017 compared with a loss of $33.7 million for the six months ended June 30, 2016.

    The following table presents our operating results for the comparable periods by reportable segment:

	Six Months Ended June 30,
Dollars in Thousands	2017							2016
Revenues:
Drilling Services:
U.S. (Lower 48) Drilling	$	6,257			3	%		$	3,150			1	%
International & Alaska Drilling	123,881				60	%		160,545				68	%
Total Drilling Services	130,138				63	%		163,695				69	%
Rental Tools Services:
U.S. Rental Tools	49,936				24	%		40,516				17	%
International Rental Tools	27,804				13	%		31,579				14	%
Total Rental Tools Services	77,740				37	%		72,095				31	%
Total revenues	207,878				100	%		235,790				100	%
Operating gross margin (loss) excluding depreciation and amortization:
Drilling Services:
U.S. (Lower 48) Drilling	(4,010		)		(64	)%		(7,239		)		(230	)%
International & Alaska Drilling	20,294				16	%		36,710				23	%
Total Drilling Services	16,284				13	%		29,471				18	%
Rental Tools Services:
U.S. Rental Tools	20,508				41	%		13,147				32	%
International Rental Tools	(4,369		)		(16	)%		(4,140		)		(13	)%
Total Rental Tools Services	16,139				21	%		9,007				12	%
Total operating gross margin (loss) excluding depreciation and amortization	32,423				16	%		38,478				16	%
Depreciation and amortization	(63,184		)					(72,131		)
Total operating gross margin (loss)	(30,761		)					(33,653		)
General and administrative expense	(13,543		)					(17,776		)
Gain (loss) on disposition of assets, net	(465		)					(62		)
Total operating income (loss)	$	(44,769	)					$	(51,491	)

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

Dollars in Thousands	U.S. (Lower 48) Drilling				International & Alaska Drilling				U.S. Rental Tools				International Rental Tools				Total
Six Months Ended June 30, 2017
Operating gross margin (loss) (1)	$	(11,761	)		$	(4,555	)		$	(798	)		$	(13,647	)		$	(30,761	)
Depreciation and amortization	7,751				24,849				21,306				9,278				63,184
Operating gross margin (loss) excluding depreciation and amortization	$	(4,010	)		$	20,294			$	20,508			$	(4,369	)		$	32,423
Six Months Ended June 30, 2016
Operating gross margin (loss) (1)	$	(17,571	)		$	8,274			$	(9,422	)		$	(14,934	)		$	(33,653	)
Depreciation and amortization	10,332				28,436				22,569				10,794				72,131
Operating gross margin (loss) excluding depreciation and amortization	$	(7,239	)		$	36,710			$	13,147			$	(4,140	)		$	38,478

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

The following table presents our average utilization rates and rigs available for service for the six months ended June 30, 2017 and 2016, respectively:

	Six Months Ended June 30,
	2017			2016
U.S. (Lower 48) Drilling
Rigs available for service (1)	13.0			13.0
Utilization rate of rigs available for service (2)	12	%		6	%
International & Alaska Drilling
Eastern Hemisphere
Rigs available for service (1)	13.0			13.0
Utilization rate of rigs available for service (2)	31	%		43	%
Latin America Region
Rigs available for service (1)	7.0			7.0
Utilization rate of rigs available for service (2)	14	%		29	%
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			22.0
Utilization rate of rigs available for service (2)	32	%		44	%

(1)

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

(2)

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

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Drilling Services Business

U.S. (Lower 48) Drilling

U.S. (Lower 48) Drilling segment revenues increased $3.1 million, or 96.9 percent, to $6.3 million for the six months ended June 30, 2017 compared with revenues of $3.2 million for the six months ended June 30, 2016. The increase was primarily due to higher utilization. Utilization increased to 12.0 percent for the six months ended June 30, 2017 from 6.0 percent for the six months ended June 30, 2016, resulting in a $2.5 million increase in revenues. The remainder of the increase was primarily driven by higher dayrates.

U.S. (Lower 48) Drilling segment operating gross margin excluding depreciation and amortization improved $3.2 million, or 44.4 percent, to a loss of $4.0 million for the six months ended June 30, 2017 compared with a loss of $7.2 million for the six months ended June 30, 2016. The improvement was primarily due to the increase in utilization discussed above and reduced costs resulting from organizational efficiency initiatives.

International & Alaska Drilling

International & Alaska Drilling segment revenues decreased $36.6 million, or 22.8 percent, to $123.9 million for the six months ended June 30, 2017 compared with $160.5 million for the six months ended June 30, 2016.

The decrease in revenues was primarily due to the following:

•	a decrease of $20.7 million in revenues related to our project services activities;

•	a decrease in reimbursable revenues of $7.4 million, which decreased revenues but had a minimal impact on operating margins;

•	a decrease of $7.1 million resulting from decreased utilization for Company-owned rigs driven by the continued impact of low oil prices resulting in reduced customer activity. Utilization for the segment decreased to 32.0 percent for the six months ended June 30, 2017 from 44.0 percent for the six months ended June 30, 2016;

•	a decrease of $4.2 million in revenues earned from mobilization and demobilization activities; and

•	a decrease of $3.7 million driven by a decline in revenues per day resulting from certain Company-owned rigs shifting to standby mode during 2017 compared with operating mode during 2016.

The decrease in revenues was partially offset by an increase of $8.3 million primarily driven by O&M activities associated with the Hibernia platform located off the Atlantic Coast of Canada.

International & Alaska Drilling segment operating gross margin excluding depreciation and amortization decreased $16.4 million, or 44.7 percent, to $20.3 million for the six months ended June 30, 2017 compared with $36.7 million for the six months ended June 30, 2016. The decrease in operating gross margin excluding depreciation and amortization was primarily due to the impact of reduced utilization and revenues per day discussed above. Additionally, the six months ended June 30, 2016 benefited from higher margin work on project services activities.

Rental Tools Services Business

U.S. Rental Tools

U.S. Rental Tools segment revenues increased $9.4 million, or 23.2 percent, to $49.9 million for the six months ended June 30, 2017 compared with $40.5 million for the six months ended June 30, 2016. The increase was primarily driven by an increase in U.S. land rental revenues driven by improved customer activity, partially offset by a decline in offshore GOM rental revenues.

U.S. Rental Tools segment operating gross margin excluding depreciation and amortization increased $7.4 million, or 56.5 percent, to $20.5 million for the six months ended June 30, 2017 compared with $13.1 million for the six months ended June 30, 2016. The increase was primarily due to the increase in revenues discussed above.

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International Rental Tools

International Rental Tools segment revenues decreased $3.8 million, or 12.0 percent, to $27.8 million for the six months ended June 30, 2017 compared with $31.6 million for the six months ended June 30, 2016. The decrease was primarily attributable to the continued reduction in customer activity and price erosion, with the largest declines in our U.K. North Sea operations and offshore rentals.

International Rental Tools segment operating gross margin excluding depreciation and amortization decreased $0.3 million, or 7.3 percent, to a loss of $4.4 million for the six months ended June 30, 2017 compared with a loss of $4.1 million for the six months ended June 30, 2016. The decrease was primarily due to the decrease in offshore rental revenues discussed above, partially offset by lower operating costs resulting from organizational efficiency initiatives.

Other Financial Data

General and administrative expense

General and administrative expense decreased $4.3 million to $13.5 million for the six months ended June 30, 2017 compared with $17.8 million for the six months ended June 30, 2016. General and administrative expense for the six months ended June 30, 2017 benefited from a reduction in incentive compensation associated with the departure of the Company’s chief financial officer and reduced overhead costs resulting from cost savings initiatives. In addition, during the six months ended June 30, 2016 we incurred higher expenses as we implemented the second phase of our new enterprise resource planning system.

Gain (loss) on disposition of assets

Net losses recognized on asset dispositions were $0.5 million and $0.1 million for the six months ended June 30, 2017 and 2016 respectively. We periodically sell equipment deemed to be excess, obsolete, or not currently required for operations.

Interest income and expense

Interest expense decreased $1.7 million to $22.0 million for the six months ended June 30, 2017 compared with $23.7 million for the six months ended June 30, 2016. The decrease in interest expense was primarily related to the write off of $1.1 million of debt issuance costs during the second quarter of 2016 in conjunction with the execution of the an amendment to our revolving credit facility. Interest income during each of the six months ended June 30, 2017 and 2016 was nominal.

Other income and expense

Other income was $1.1 million and $2.1 million for the six months ended June 30, 2017 and 2016, respectively. Other income for both periods included the impact of foreign currency fluctuations. Additionally, other income for the six months ended June 30, 2016 included a reclassification of $1.9 million of realized foreign currency translation gains from accumulated other comprehensive income.

Income tax expense (benefit)

During the six months ended June 30, 2017, we had income tax expense of $4.1 million compared with income tax expense of $62.6 million during the six months ended June 30, 2016.  Despite the pre-tax loss for the six months ended June 30, 2017, we recognized income tax expense due to the jurisdictional mix of income and loss during the period, along with our continued inability to recognize the benefits associated with certain losses as a result of valuation allowances. During the six months ended June 30, 2016, we recognized income tax expense of $62.6 million as a result of recording valuation allowances against our U.S. domestic deferred tax assets, which primarily consist of U.S. federal net operating losses.

Backlog

Backlog is our estimate of the dollar amount of revenues we expect to realize in the future as a result of executing awarded drilling contracts. The Company’s backlog of firm orders was approximately $289 million at June 30, 2017 and $446 million at June 30, 2016, and is primarily attributable to the International & Alaska Drilling segment of our Drilling Services business. We estimate that, as of June 30, 2017, 29 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 2016 Form 10-K. 

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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 term liquidity requirements we primarily rely on our cash from operations. We also have access to cash through the Revolver, subject to our compliance with the covenants contained in the Second Amended and Restated Senior Secured Credit Agreement, as amended from time-to-time (2015 Secured Credit Agreement). We expect that these sources of liquidity will be sufficient to provide us the ability to fund our current operations and required capital expenditures. We may need to fund expansion capital expenditures, acquisitions, debt principal payments, or pursuits of business opportunities that support our strategy, through additional borrowings or the issuance of additional common stock or other forms of equity. We do not pay dividends on our common stock.

In February 2017, we issued 12,000,000 shares of common stock, par value $0.16 2/3 per share, at the public offering price of $2.10 per share and 500,000 shares of 7.25% Series A Mandatory Convertible Preferred Stock (Convertible Preferred Stock), par value $1.00 per share, with a liquidation preference of $100 per share, for total net proceeds of $72.3 million, after underwriting discount and offering expenses.

Dividends on our Convertible Preferred Stock will be payable on a cumulative basis when, as and if declared by our board of directors, or an authorized committee of our board of directors, at an annual rate of 7.25 percent of the liquidation preference of $100 per share. We may pay declared dividends in cash or, subject to certain limitations, in shares of our common stock, or in any combination of cash and shares of our common stock on March 31, June 30, September 30 and December 31 of each year, commencing on June 30, 2017 and ending on, and including, March 31, 2020.

Liquidity

The following table provides a summary of our total liquidity:

	June 30, 2017
Dollars in thousands
Cash and cash equivalents on hand (1)	$	146,234
Availability under Revolver (2)	82,348
Total liquidity	$	228,582

(1) As of June 30, 2017, approximately $40.4 million of the $146.2 million of cash and equivalents was held by our foreign subsidiaries.

(2) Availability under the undrawn $100 million Revolver was reduced by $17.7 million comprised of $5.8 million of letters of credit outstanding and $11.9 million of reduced availability due to our Senior Secured Leverage Ratio covenant. As of June 30, 2017, we were in compliance with all covenants contained in the 2015 Secured Credit Agreement.

The earnings of foreign subsidiaries as of June 30, 2017 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 could 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 June 30, 2017, we have no energy, commodity, or foreign currency derivative contracts.

Cash Flow Activity

As of June 30, 2017, we had cash and cash equivalents of $146.2 million, an increase of $26.5 million from cash and cash equivalents of $119.7 million at December 31, 2016. The following table provides a summary of our cash flow activity:

	Six Months Ended June 30,
Dollars in thousands	2017				2016
Operating activities	$	(17,568	)		$	(198	)
Investing activities	(26,374		)		(14,870		)
Financing activities	70,485				(10,192		)
Net change in cash and cash equivalents	$	26,543			$	(25,260	)

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Operating Activities

Cash flows from operating activities were a use of $17.6 million for the six months ended June 30, 2017 compared with a use of $0.2 million for the six months ended June 30, 2016. Cash flows from operating activities in each period were largely impacted by our earnings and changes in working capital. Changes in working capital were a use of cash of $15.5 million for the six months ended June 30, 2017 compared with a source of cash of $8.5 million for the six months ended June 30, 2016. In addition to the impact of earnings and working capital changes, cash flows from operating activities in each period were impacted by non-cash charges such as depreciation expense, losses on asset sales, deferred tax expenses and benefits, stock-based awards activity, and amortization of debt issuance costs.

Historically, 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 oil and natural gas services market over the past few years, our short-term focus is to preserve liquidity by managing our costs and capital expenditures. While the overall market for oilfield services remains challenging, we are beginning to see recovery in the market that is expected to shift working capital into a use of cash and drive increased capital spending as we pursue attractive investment opportunities.

Investing Activities

Cash flows from investing activities were a use of $26.4 million for the six months ended June 30, 2017 compared with a use of $14.9 million for the six months ended June 30, 2016. Our primary uses of cash during the six months ended June 30, 2017 and 2016 were $26.6 million and $16.3 million, respectively, for capital expenditures. Capital expenditures in each period were primarily for tubular and other products for our Rental Tools Services business and for rig-related maintenance.

Financing Activities

Cash flows from financing activities were a source of $70.5 million for the six months ended June 30, 2017, primarily related to the issuances of common stock and Convertible Preferred Stock, which yielded combined proceeds of $72.3 million, net of underwriting discount and offering expenses. In June 2017, the Company paid dividends of $1.2 million on our Convertible Preferred Stock. For the 2016 comparable period, cash flows from financing activities were a use of $10.2 million primarily due to payment of $6.0 million of the contingent consideration related to the acquisition of a business in April 2015 and $3.4 million in connection with the final payment of the purchase price for the remaining noncontrolling interest of ITS Arabia Limited.

Long-Term Debt Summary

Our principal amount of long-term debt, including current portion, was $577.1 million as of June 30, 2017 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

•$7.9 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 July 2022 (6.75% Notes) pursuant to an Indenture between the Company and The Bank of New York Mellon Trust Company, N.A., as trustee. 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 2015 Secured Credit Agreement and our 7.50% Senior Notes due August 2020 (7.50% Notes, and collectively with the 6.75% Notes, the Senior Notes). Interest on the 6.75% Notes is payable on January 15 and July 15 of each year, beginning July 15, 2014. Debt issuance costs related to the 6.75% Notes of approximately $7.6 million ($5.0 million net of amortization as of June 30, 2017) are being amortized over the term of the notes using the effective interest rate method.

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 limits 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

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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. 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 ($2.8 million, net of amortization as of June 30, 2017) are being amortized over the term of the notes using the effective interest rate method.

We may redeem all or a part of the 7.50% Notes upon appropriate notice, at redemption prices decreasing each year after August 1, 2016 to par beginning August 1, 2018. As of June 30, 2017, the redemption price is 103.75 percent and we have not made any redemptions to date. 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 limits 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. The 2015 Secured Credit Agreement was originally comprised of a $200.0 million revolving credit facility (Revolver) set to mature on January 26, 2020. Four amendments to the 2015 Secured Credit Agreement have been executed, which have, among other things, reduced the size of the revolver to $100 million, suspended the Leverage Ratio, Consolidated Interest Coverage Ratio, Senior Secured Leverage Ratio, and Asset Coverage Ratio covenants during specific time periods, increased the Applicable Rate for certain higher levels of consolidated leverage to a maximum of 4.00 percent per annum for Eurodollar Rate loans and to a maximum of 3.00 percent per annum for Base Rate loans, established anti-hoarding language restricting our ability to retain more than $50 million in U.S. bank accounts when there are outstanding borrowings under the Revolver, and established a $75 million Junior Lien Debt capacity.

The maximum permitted Senior Secured Leverage Ratio was 2.20:1.00 for the fiscal quarter ending June 30, 2017, decreases to 1.75:1.00 in the third quarter of 2017, and to 1.50:1.00 in the fourth quarter of 2017 and remains at 1.50:1.00 thereafter. The Asset Coverage Ratio covenant, currently at 1.10:1.00, increases to 1.25: 1.00 in the fourth quarter of 2017 and remains at 1.25:1.00 thereafter. The Consolidated Interest Coverage Ratio covenant will be reinstated in the fourth quarter of 2017 with the ratio established at 1.00:1.00, which increases by 0.25 each subsequent quarter until reaching 2.00:1.00 in the fourth quarter of 2018, and remains at 2.00:1.00 thereafter. The Leverage Ratio covenant will be reinstated in the fourth quarter of 2018 with the ratio established at 4.25:1.00.

On February 21, 2017, we executed the fourth amendment to the 2015 Secured Credit Agreement (the Fourth Amendment) which, among other things, permits the sale and issuance of certain equity interests of the Company, including the Convertible Preferred Stock, and permits the Company to pay dividends on the Convertible Preferred Stock, up to certain aggregate amounts specified therein. The debt issuance costs incurred relating to the Fourth Amendment were nominal. Debt issuance costs remaining as of June 30, 2017 were $1.0 million which are being amortized through January 2020 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. As of June 30, 2017, we were in compliance with all covenants contained in the 2015 Secured Credit Agreement though our ability to access the full $100 million of the Revolver was restricted to $82.3 million due to $5.8 million in letters of credit outstanding and $11.9 million related to a cap imposed by our Senior Secured Leverage Ratio covenant calculation.

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Our Revolver is available for general corporate purposes and to support letters of credit. Interest on Revolver loans accrues at a Base Rate plus an Applicable Rate or LIBOR plus an Applicable Rate. Revolving loans are available subject to a quarterly asset coverage ratio calculation based on the Orderly Liquidation Value of certain specified rigs including barge rigs in the GOM and land rigs in Alaska, and certain U.S.-based rental equipment of the Company and its subsidiary guarantors and a percentage of eligible domestic accounts receivable. Letters of credit outstanding against the Revolver as of June 30, 2017 totaled $5.8 million. There were no amounts drawn on the Revolver as of June 30, 2017.    

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

    

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Item 3. Quantitative and Qualitative Disclosures about Market Risk

There has been no material change in the market risk faced by us from that reported in our 2016 Form 10-K. For more information on market risk, see Part II, Item 7A in our 2016 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 Interim 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 Interim Chief Financial Officer concluded that our disclosure controls and procedures were effective, as of June 30, 2017, 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 Interim Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

Changes in Internal Controls Over Financial Reporting

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

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PART II. OTHER INFORMATION 

Item 1. Legal Proceedings

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

Item 1A. Risk Factors

There have been no material changes from the risk factors disclosed in Item 1A. Risk Factors of our 2016 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 March 9, 2017 (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on March 14, 2017).
3.3		—		Certificate of Designations of 7.25% Series A Mandatory Convertible Preferred Stock of Parker Drilling Company, dated February 27, 2017 (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on February 27, 2017).
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		—		Jon-Al Duplantier, Senior Vice President, Chief Administrative Officer, Interim Chief Financial Officer and General Counsel, Rule 13a-14(a)/15d-14(a) Certification.
32.1		—		Gary G. Rich, Chairman, President and Chief Executive Officer, Section 1350 Certification.
32.2		—		Jon-Al Duplantier, Senior Vice President, Chief Administrative Officer, Interim Chief Financial Officer and General Counsel, Section 1350 Certification.
101.INS		—		XBRL Instance Document.
101.SCH		—		XBRL Taxonomy Schema Document.
101.CAL		—		XBRL Calculation Linkbase Document.
101.LAB		—		XBRL Label Linkbase Document.
101.PRE		—		XBRL Presentation Linkbase Document.
101.DEF		—		XBRL Definition Linkbase Document.

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SIGNATURES

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

 

		PARKER DRILLING COMPANY
Date:	August 3, 2017	By:		/s/ Gary G. Rich
				Gary G. Rich Chairman, President and Chief Executive Officer
		By:		/s/ Jon-Al Duplantier
				Jon-Al Duplantier Senior Vice President, Chief Administrative Officer, Interim Chief Financial Officer and General Counsel

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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 March 9, 2017 (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on March 14, 2017).
3.3		—		Certificate of Designations of 7.25% Series A Mandatory Convertible Preferred Stock of Parker Drilling Company, dated February 27, 2017 (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on February 27, 2017).
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		—		Jon-Al Duplantier, Senior Vice President, Chief Administrative Officer, Interim Chief Financial Officer and General Counsel, Rule 13a-14(a)/15d-14(a) Certification.
32.1		—		Gary G. Rich, Chairman, President and Chief Executive Officer, Section 1350 Certification.
32.2		—		Jon-Al Duplantier, Senior Vice President, Chief Administrative Officer, Interim Chief Financial Officer and General Counsel, Section 1350 Certification.
101.INS		—		XBRL Instance Document.
101.SCH		—		XBRL Taxonomy Schema Document.
101.CAL		—		XBRL Calculation Linkbase Document.
101.LAB		—		XBRL Label Linkbase Document.
101.PRE		—		XBRL Presentation Linkbase Document.
101.DEF		—		XBRL Definition Linkbase Document.

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