PARKER DRILLING CO /DE/ - Quarter Report: 2015 September (Form 10-Q)

Large accelerated filer

Accelerated filer

Non-accelerated filer

¨ (Do not check if a smaller reporting company)

Smaller reporting company

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)



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

For The Quarterly Period Ended September 30, 2015



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

For the transition period from to

Commission File Number 1-7573

PARKER DRILLING COMPANY

(Exact name of registrant as specified in its charter)



Delaware		73-0618660
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

5 Greenway Plaza, Suite 100, Houston, Texas		77046
(Address of principal executive offices)		(Zip code)

(281) 406-2000

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files. Yes x No ¨

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

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 November 2, 2015 there were 123,179,100 common shares outstanding.

TABLE OF CONTENTS



	Page
Part I. Financial Information
Item 1. Financial Statements	3
Consolidated Condensed Balance Sheets as at September 30, 2015 (Unaudited) and December 31, 2014	3
Consolidated Condensed Statements of Operations (Unaudited) for the Three and Nine Months Ended September 30, 2015 and 2014	4
Consolidated Condensed Statements of Comprehensive Income (Loss) (Unaudited) for the Three and Nine Months Ended September 30, 2015 and 2014	5
Consolidated Condensed Statements of Cash Flows (Unaudited) for the Nine Months Ended September 30, 2015 and 2014	6
Notes to the Unaudited Consolidated Condensed Financial Statements	7
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	30
Item 3. Quantitative and Qualitative Disclosures about Market Risk	45
Item 4. Controls and Procedures	45

Part II. Other Information
Item 1. Legal Proceedings	46
Item 1A. Risk Factors	46
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	46
Item 3. Defaults Upon Senior Securities	46
Item 4. Mine Safety Disclosures	46
Item 5. Other Information	46
Item 6. Exhibits	47
Signatures	48

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATED CONDENSED BALANCE SHEETS

(Dollars in Thousands)



	September 30, 2015			December 31, 2014
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	104,651		$	108,456
Accounts and Notes Receivable, net of allowance for bad debts of $9,691 at September 30, 2015 and $11,188 at December 31, 2014.	224,996			270,952
Rig materials and supplies	38,516			47,943
Deferred costs	2,961			5,673
Deferred income taxes	5,448			7,476
Other tax assets	7,832			10,723
Other current assets	17,201			18,556
Total current assets	401,605			469,779
Property, plant and equipment, net of accumulated depreciation of $1,285,222 at September 30, 2015 and $1,201,058 at December 31, 2014.	841,923			895,940
Goodwill (Note 3)	6,708			—
Intangible assets, net (Note 3)	14,741			4,286
Debt issuance costs	13,136			12,526
Deferred income taxes	133,058			122,689
Other noncurrent assets	31,012			15,439
Total assets	$	1,442,183		$	1,520,659
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Current portion of long-term debt	$	—		$	10,000
Accounts payable and accrued liabilities	143,576			154,479
Accrued income taxes	6,594			14,186
Total current liabilities	150,170			178,665
Long-term debt	585,000			605,000
Other long-term liabilities	20,141			18,665
Long-term deferred tax liability	75,197			52,115
Commitments and contingencies (Note 12)
Stockholders’ equity:
Common stock	20,517			20,325
Capital in excess of par value	670,700			666,769
Accumulated deficit	(83,592		)	(24,165		)
Accumulated other comprehensive (loss)	(1,127		)	(498		)
Total controlling interest stockholders’ equity	606,498			662,431
Noncontrolling interest	5,177			3,783
Total equity	611,675			666,214
Total liabilities and stockholders’ equity	$	1,442,183		$	1,520,659

See accompanying notes to the unaudited consolidated condensed financial statements.

PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENTS OF OPERATIONS

(Dollars in Thousands, Except Per Share Data)

(Unaudited)



	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
Revenues	$	173,418		$	242,012		$	563,435		$	725,471
Expenses:
Operating expenses	128,963			160,797			411,802			501,391
Depreciation and amortization	39,584			36,149			118,474			106,666
	168,547			196,946			530,276			608,057
Total operating gross margin	4,871			45,066			33,159			117,414
General and administration expense	(8,895		)	(9,370		)	(29,243		)	(25,341		)
Provision for reduction in carrying value of certain assets	(906		)	—			(3,222		)	—
Gain (loss) on disposition of assets, net	383			(457		)	2,686			433
Total operating income (loss)	(4,547		)	35,239			3,380			92,506
Other income and (expense):
Interest expense	(11,293		)	(10,848		)	(33,767		)	(33,486		)
Interest income	7			36			209			156
Loss on extinguishment of debt	—			—			—			(30,152		)
Other	(719		)	(536		)	(3,628		)	1,391
Total other expense	(12,005		)	(11,348		)	(37,186		)	(62,091		)
Income (loss) before income taxes	(16,552		)	23,891			(33,806		)	30,415
Income tax expense	31,930			11,014			24,832			14,093
Net income (loss)	(48,482		)	12,877			(58,638		)	16,322
Less: Net income attributable to noncontrolling interest	138			311			789			624
Net income (loss) attributable to controlling interest	$	(48,620	)	$	12,566		$	(59,427	)	$	15,698
Basic earnings (loss) per share	$	(0.40	)	$	0.10		$	(0.49	)	$	0.13
Diluted earnings (loss) per share	$	(0.40	)	$	0.10		$	(0.49	)	$	0.13

Number of common shares used in computing earnings per share:
Basic	122,933,518			121,523,674			122,430,957			120,994,728
Diluted	122,933,518			123,177,753			122,430,957			122,972,014

See accompanying notes to the unaudited consolidated condensed financial statements.

PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Dollars in Thousands)

(Unaudited)



	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
Comprehensive income:
Net income (loss)	$	(48,482	)	$	12,877		$	(58,638	)	$	16,322
Other comprehensive income (loss), net of tax:
Currency translation difference on related borrowings	(1,285		)	(1,780		)	(2,308		)	(2,248		)
Currency translation difference on foreign currency net investments	588			615			1,462			1,126
Total other comprehensive income (loss), net of tax:	(697		)	(1,165		)	(846		)	(1,122		)
Comprehensive income (loss)	(49,179		)	11,712			(59,484		)	15,200
Comprehensive (loss) attributable to noncontrolling interest	(82		)	(289		)	(571		)	(523		)
Comprehensive income (loss) attributable to controlling interest	$	(49,261	)	$	11,423		$	(60,055	)	$	14,677

See accompanying notes to the unaudited consolidated condensed financial statements.

PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)

(Unaudited)



	Nine Months Ended September 30,
	2015			2014
Cash flows from operating activities:
Net income (loss)	$	(58,638	)	$	16,322
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization	118,474			106,666
Accretion of contingent consideration	547			—
Loss on extinguishment of debt	—			30,152
Provision for reduction in carrying value of certain assets	3,222			—
(Gain) loss on disposition of assets	(2,686		)	(433		)
Deferred income tax benefit	10,259			73
Expenses not requiring cash	8,029			10,141
Change in assets and liabilities:
Accounts and notes receivable	51,254			(5,188		)
Other assets	1,486			7,554
Accounts payable and accrued liabilities	(15,790		)	(10,539		)
Accrued income taxes	(7,305		)	(10,397		)
Net cash provided by operating activities	108,852			144,351

Cash flows from investing activities:
Capital expenditures	(72,469		)	(151,109		)
Proceeds from the sale of assets	731			2,294
Proceeds from insurance settlements	2,500			—
Acquisition, net of cash acquired	(10,431		)	—
Net cash (used in) investing activities	(79,669		)	(148,815		)

Cash flows from financing activities:
Proceeds from issuance of debt	—			400,000
Repayments of long-term debt	(30,000		)	(432,500		)
Payments of debt issuance costs	(1,996		)	(7,630		)
Payments of debt extinguishment costs	—			(26,214		)
Excess tax benefit (expense) from stock based compensation	(992		)	430
Net cash (used in) financing activities	(32,988		)	(65,914		)

Net (decrease) in cash and cash equivalents	(3,805		)	(70,378		)
Cash and cash equivalents, beginning of year	108,456			148,689
Cash and cash equivalents, end of period	$	104,651		$	78,311

Supplemental cash flow information:
Interest paid	$	41,393		$	41,558
Income taxes paid	$	21,627		$	15,787

See accompanying notes to the unaudited consolidated condensed financial statements.

PARKER DRILLING COMPANY AND SUBSIDIARIES

NOTES TO THE UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

Note 1 - General

In the opinion of the management of Parker Drilling Company (Parker Drilling or the Company), the accompanying unaudited consolidated condensed financial statements reflect all adjustments normally recurring which we believe are necessary for a fair presentation of: (1) Parker Drilling’s financial position as of September 30, 2015 and December 31, 2014, (2) Parker Drilling’s results of operations for the three and nine month periods ended September 30, 2015 and 2014, (3) Parker Drilling’s consolidated condensed statement of comprehensive income for the three and nine month periods ended September 30, 2015 and 2014, and (4) Parker Drilling’s cash flows for the nine month periods ended September 30, 2015 and 2014. Results for the three and nine month periods ended September 30, 2015 are not necessarily indicative of the results that will be realized for the year ending December 31, 2015. The financial statements should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2014.

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

In our Drilling Services business, we own and operate drilling rigs and drilling-related equipment and also perform drilling-related services, referred to as operations and maintenance (O&M) services, on a contracted basis for operators who own their own drilling rigs, but choose Parker Drilling to operate the rigs for them. In addition, we provide consulting services, such as engineering, procurement, project management and commissioning of customer-owned drilling facility projects. We have extensive experience and expertise in drilling geologically difficult wells and in managing the logistical and technological challenges of operating in remote, harsh and ecologically sensitive areas. Our U.S. (Lower 48) Drilling segment includes our Gulf of Mexico (GOM) barge drilling fleet and United States (U.S.) based O&M services. Our GOM barge drilling business operates barge rigs that drill for oil and natural gas in shallow waters in and along the inland waterways and coasts of Louisiana, Alabama, and Texas. The majority of these wells are drilled in shallow water depths ranging from 6 to 12 feet. Our International & Alaska Drilling segment includes operations related to Parker-owned and customer-owned rigs in the Eastern Hemisphere and Latin America regions as well as Alaska.

Our Rental Tools Services business provides premium rental equipment and services to exploration and production companies, drilling contractors and service companies on land and offshore in the U.S. and select international markets. Tools we provide include standard and heavy-weight drill pipe, all of which are available with standard or high-torque connections, tubing, pressure control equipment including blow-out preventers (BOPs), drill collars and more. We also provide well construction services which include tubular running services and downhole tools and well intervention services which include whipstock, fishing products and related services, as well as inspection and machine shop support.

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. In the second quarter of 2015 we recognized through other income and expense a $0.9 million loss related to the divestiture of our controlling interest in a joint venture.

Noncontrolling Interest — We apply accounting standards related to noncontrolling interests for ownership interests in our subsidiaries held by parties other than Parker Drilling. The entities that comprise the noncontrolling interest include ITS Arabia Limited and ITS Egypt SAE. We report noncontrolling interest as equity on the consolidated balance sheets and report net income (loss) attributable to controlling interest and to noncontrolling interest separately on the consolidated statements of operations.

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 contracts include engineering, consulting, and project management scopes of work and revenue is typically recognized on a time and materials basis.

Reimbursable Costs — The Company recognizes reimbursements received for out-of-pocket expenses incurred as revenues and accounts for out-of-pocket expenses as direct operating costs. Reimbursable costs totaled $20.8 million and $19.3 million for the three months ended September 30, 2015 and 2014, respectively, and $68.4 million and $57.5 million for the nine months ended September 30, 2015 and 2014, respectively. Additionally, the Company typically receives a nominal handling fee, which is recognized as earned revenues in our consolidated statement of operations.

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

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

Goodwill — We account for all business combinations using the acquisition method of accounting. Under this method, assets and liabilities, including any remaining noncontrolling interests, are recognized at fair value at the date of acquisition. The excess of the purchase price over the fair value of assets acquired, net of liabilities assumed, plus the value of any noncontrolling interests, is recognized as goodwill. We are required to test goodwill for impairment on an annual basis, and more frequently when negative conditions or other triggering events arise. See Note 3 - Goodwill and Intangible Assets for further discussion.

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

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 major, independent, national and international oil and gas companies and integrated service providers. 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 27.0 percent of our revenues for the nine months ended September 30, 2015. Each of our segments depends on a limited number of key customers and the loss of any one or more key customers could have a material adverse effect on a segment.

At September 30, 2015 and December 31, 2014, we had deposits in domestic banks in excess of federally insured limits of approximately $62.1 million and $59.3 million, respectively. In addition, as of September 30, 2015 and December 31, 2014, we had deposits that were not insured in foreign banks of $43.1 million and $54.4 million, respectively.

Income Taxes - Income taxes are accounted for under the asset and liability method and have been provided based upon tax laws and rates in effect in the countries in which operations are conducted and income is earned. 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.

Note 2 - Acquisitions

Acquisition of ITS

On April 22, 2013 we acquired International Tubular Services Limited (ITS) and related assets (the ITS Acquisition) for an initial purchase price of $101.0 million paid at the closing of the ITS Acquisition. An additional $24.0 million was deposited into an escrow account, to be payable to the seller or to us, as the case may be, in accordance with the ITS Acquisition agreement (the Acquisition Agreement). As of September 30, 2015, the escrow account is closed, with $20.7 million of the cash deposited in escrow released to the seller (or to third parties on behalf of the seller) and $3.3 million released to us ($2.75 million received in 2014 and $0.5 million received during the nine months ended September 30, 2015).

Acquisition of 2M-Tek

On April 17, 2015 we acquired 2M-Tek, a Louisiana-based manufacturer of equipment for tubular running and related well services for an initial purchase price of $10.4 million paid at the closing of the acquisition (the 2M-Tek Acquisition), plus $8.0 million of contingent consideration payable to the seller upon the achievement of certain milestones over the 24-month period following the close of the 2M-Tek Acquisition. The fair value of the consideration transferred was $17.2 million, which includes the $10.4 million paid at closing plus the estimated fair value of the contingent consideration of $6.8 million. We have recorded the fair value of the liability for contingent consideration in "accrued liabilities" on our condensed consolidated balance sheet. The operations and related assets acquired and liabilities assumed will be reported as part of our Rental Tools segment. This acquisition will complement our existing international tubular running services (TRS) business. The acquisition secures our access to a proprietary casing running tool while minimizing the total capital cost of TRS equipment going forward.

Allocation of Consideration Transferred to Net Assets Acquired

The purchase price has been allocated to the fair value of the assets acquired and liabilities assumed. The allocation is preliminary and based on estimates and assumptions that are subject to change within the purchase price allocation period (generally one year from the acquisition date). The company used recognized valuation techniques to determine the fair value of the assets and liabilities. The assets acquired and liabilities assumed were recorded at fair value in accordance with U.S. GAAP. Acquisition date fair values represent either Level 2 (as defined in Note 11 - Fair Value of Financial Instruments) fair value measurements (current assets and liabilities, property plant and equipment) or Level 3 (as defined in Note 11) fair value measurements (intangible assets).



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

Pro forma results of operations have not been presented because the effect of the acquisition was not material to our results of operations. Acquisition-related costs for the nine months ended September 30, 2015 were approximately $0.4 million.

Note 3 - Goodwill and Intangible Assets

We account for all business combinations using the acquisition method of accounting. Under this method, assets and liabilities, including any remaining noncontrolling interests, are recognized at fair value at the date of acquisition. The excess of the purchase price over the fair value of assets acquired, net of liabilities assumed, plus the value of any noncontrolling interests, is recognized as goodwill.

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

Goodwill

The change in the carrying amount of goodwill for the period ended September 30, 2015 is as follows:



Dollars in thousands	Goodwill
Balance at December 31, 2014	$	—
Acquisition	6,708
Balance at September 30, 2015	$	6,708

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

Intangible Assets

Intangible Assets consist of the following:



		As of September 30, 2015
Dollars in thousands	Estimated Useful Life (Years)	Gross Carrying Amount		Accumulated Amortization			Net Carrying Amount
Amortized intangible assets:
Developed Technology	6	$	11,630	$	(969	)	$	10,661
Customer Relationships	3	5,400		(4,394		)	1,006
Trademarks and trade names	5	4,940		(1,866		)	3,074
Total Amortized intangible assets		$	21,970	$	(7,229	)	$	14,741

Amortization expense was $1.2 million and $0.6 million for the three months ended September 30, 2015 and 2014, and $3.1 million and $1.9 million for the nine months ended September 30, 2015 and 2014, respectively.

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



Dollars in thousands	Expected future intangible amortization expense
2015	$	1,204
2016	$	3,549
2017	$	2,860
2018	$	2,306
2019	$	2,306
Beyond 2019	$	2,516

Note 4 - Property, Plant and Equipment

Provision for Reduction in Carrying Value of an Asset

We review the carrying amounts of long-lived assets for potential impairment when events occur or circumstances change that indicate the carrying values of such assets may not be recoverable. During the 2015 third quarter, we identified an impairment trigger related to the continued decline in oil prices and expected slower recovery. Therefore, we performed a recoverability test for our respective asset groups. Based on the results of our recoverability test, the current carrying values of our asset groups are fully recoverable through our future estimated cash flows and thus not subject to impairment at September 30, 2015.

During the 2015 third quarter, for specific assets related to our Alaska operations, management concluded that the carrying value of the assets is no longer recoverable. Therefore, during the 2015 third quarter we recorded a provision for reduction in carrying value of $0.9 million. Fair value was based on expected future cash flows using Level 3 inputs in accordance with fair value measurement requirements. During the 2015 second quarter, we recorded a $2.3 million provision for reduction in carrying value related to certain international rental tools and drilling rigs. Management concluded that due to changing market conditions the rigs were no longer marketable and the carrying value of the rigs and equipment was no longer recoverable.

Asset impairment evaluations are, by nature, highly subjective. They involve expectations about future cash flows generated by our assets and reflect management’s assumptions and judgments regarding future industry conditions and their effect on future utilization levels, dayrates and costs. The use of different estimates and assumptions could result in materially different carrying values of our assets.

Note 5 - Earnings (Loss) Per Share (EPS)



	Three Months Ended September 30, 2015
	Income (Numerator)			Shares (Denominator)	Per-Share Amount
Basic EPS	$	(48,620,000	)	122,933,518	$	(0.40	)
Effect of dilutive securities:
Restricted stock units	—			—	—
Diluted EPS	$	(48,620,000	)	122,933,518	$	(0.40	)

	Nine Months Ended September 30, 2015
	Income (Numerator)			Shares (Denominator)	Per-Share Amount
Basic EPS	$	(59,427,000	)	122,430,957	$	(0.49	)
Effect of dilutive securities:
Restricted stock units	—			—	—
Diluted EPS	$	(59,427,000	)	122,430,957	$	(0.49	)

	Three Months Ended September 30, 2014
	Income (Numerator)			Shares (Denominator)	Per-Share Amount
Basic EPS	$	12,566,000		121,523,674	$	0.10
Effect of dilutive securities:
Restricted stock units	—			1,654,079	—
Diluted EPS	$	12,566,000		123,177,753	$	0.10

	Nine Months Ended September 30, 2014
	Income (Numerator)			Shares (Denominator)	Per-Share Amount
Basic EPS	$	15,698,000		120,994,728	$	0.13
Effect of dilutive securities:
Restricted stock units	—			1,977,286	—
Diluted EPS	$	15,698,000		122,972,014	$	0.13

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

For the three and nine months ended September 30, 2014, weighted-average shares outstanding used in our computation of diluted EPS includes the dilutive effect of common shares potentially issuable in connection with outstanding restricted stock unit awards.

Note 6 - Accumulated Other Comprehensive Loss

Accumulated other comprehensive loss consisted of the following:



Dollars in thousands	Foreign Currency Items
December 31, 2014	$	(498	)
Current period other comprehensive (loss)	(629		)
September 30, 2015	$	(1,127	)

No amounts were reclassified out of accumulated other comprehensive income for the three and nine months ended September 30, 2015.

Note 7 - Reportable Segments

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

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



	Three Months Ended September 30,						Nine Months Ended September 30,
Dollars in thousands	2015			2014			2015			2014
Revenues: ⁽¹⁾
U.S. (Lower 48) Drilling	$	5,961		$	44,409		$	26,906		$	126,281
International & Alaska Drilling	110,661			109,892			339,551			343,803
Rental Tools	56,796			87,711			196,978			255,387
Total revenues	173,418			242,012			563,435			725,471
Operating gross margin: ⁽²⁾
U.S. (Lower 48) Drilling	(7,397		)	16,283			(20,673		)	42,829
International & Alaska Drilling	13,212			9,131			37,428			23,824
Rental Tools	(944		)	19,652			16,404			50,761
Total operating gross margin	4,871			45,066			33,159			117,414
General and administrative expense	(8,895		)	(9,370		)	(29,243		)	(25,341		)
Provision for reduction in carrying value of certain assets	(906		)	—			(3,222		)	—
Gain (loss) on disposition of assets, net	383			(457		)	2,686			433
Total operating income (loss)	(4,547		)	35,239			3,380			92,506
Interest expense	(11,293		)	(10,848		)	(33,767		)	(33,486		)
Interest income	7			36			209			156
Loss on extinguishment of debt	—			—			—			(30,152		)
Other income (loss)	(719		)	(536		)	(3,628		)	1,391
Income (loss) from continuing operations before income taxes	$	(16,552	)	$	23,891		$	(33,806	)	$	30,415

(1)For the nine months ended September 30, 2015, our largest customer, Exxon Neftegas Limited (ENL), constituted approximately 27.0 percent of our total consolidated revenues and approximately 44.7 percent of our International & Alaska Drilling segment revenues. For the nine months ended September 30, 2014, our largest customer, ENL, constituted approximately 18.9 percent of our total consolidated revenues and approximately 39.9 percent of our International & Alaska Drilling segment revenues.

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

Note 8 - Accounting for Uncertainty in Income Taxes

We apply the accounting guidance related to accounting for uncertainty in income taxes. This guidance prescribes a recognition threshold and a measurement attribute for the financial statement recognition and measurement of tax positions taken or expected to be taken in a tax return. For those benefits to be recognized, a tax position must be more likely than not to be sustained upon examination by taxing authorities. At September 30, 2015 and September 30, 2014, we had a liability for unrecognized tax benefits of $8.2 million (which includes $3.6 million of benefits which would favorably impact our effective tax rate upon recognition), primarily related to foreign operations. In addition, we recognize interest and penalties that could be applied to uncertain tax positions in periodic income tax expense. As of September 30, 2015 and December 31, 2014, we had approximately $3.7 million and $3.3 million, respectively, of accrued interest and penalties related to uncertain tax positions. Management believes the Company is properly reserved with respect to accounting for uncertainty in income taxes.

Note 9 - Income Tax Benefit/Expense

During the third quarter of 2015 we had income tax expense of $31.9 million compared to expense of $11.0 million for the third quarter of 2014. Despite the pre-tax loss for the 2015 third quarter, we recognized income tax expense as a result of recording a valuation allowance of $36.6 million primarily on U.S. foreign tax credits and certain foreign net operating losses. We established the valuation allowance based on the weight of available evidence, both positive and negative, including results of recent and current operations and our estimates of future taxable income or loss by jurisdiction in which we operate. 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 business considerations. 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.

Note 10 - Long-Term Debt

The following table illustrates our debt portfolio as of September 30, 2015 and December 31, 2014:



Dollars in thousands	September 30, 2015		December 31, 2014
6.75% Senior Notes, due July 2022	$	360,000	$	360,000
7.50% Senior Notes, due August 2020	225,000		225,000
Term Note, due December 2017	—		30,000
Total debt	585,000		615,000
Less current portion ⁽¹⁾	—		10,000
Total long-term debt	$	585,000	$	605,000

(1) Current portion of the Term Loan.

6.75% Senior Notes, due July 2022

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

The 6.75% Notes are general unsecured obligations of the Company and rank equal in right of payment with all of our existing and future senior unsecured indebtedness. The 6.75% Notes are jointly and severally guaranteed by all of our subsidiaries that guarantee indebtedness under the Second Amended and Restated Senior Secured Credit Agreement (2015 Secured Credit Agreement) and our 7.50% Senior Notes due 2020 (7.50% Notes, and collectively with the 6.75% Notes, the Senior Notes). Interest on the 6.75% Notes is payable on January 15 and July 15 of each year, beginning July 15, 2014. Debt issuance costs related to the 6.75% Notes of approximately $7.6 million ($6.4 million net of amortization as of September 30, 2015) are being amortized over the term of the notes using the effective interest rate method.

At any time prior to January 15, 2017, we may redeem up to 35 percent of the aggregate principal amount of the 6.75% Notes at a redemption price of 106.75 percent of the principal amount, plus accrued and unpaid interest to the redemption date, with the net cash proceeds of certain equity offerings by us. On and after January 15, 2018, we may redeem all or a part of the 6.75% Notes upon appropriate notice, at a redemption price of 103.375 percent of the principal amount, and at redemption prices decreasing each year thereafter to par beginning January 15, 2020. If we experience certain changes in control, we must offer to repurchase the 6.75% Notes at 101.0 percent of the aggregate principal amount, plus accrued and unpaid interest and additional interest, if any, to the date of repurchase.

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

7.50% Senior Notes, due August 2020

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

The 7.50% Notes are general unsecured obligations of the Company and rank equal in right of payment with all of our existing and future senior unsecured indebtedness. The 7.50% Notes are jointly and severally guaranteed by all of our subsidiaries that guarantee indebtedness under the 2015 Secured Credit Agreement and the 6.75% Notes. Interest on the 7.50% Notes is payable on February 1 and August 1 of each year, beginning February 1, 2014. Debt issuance costs related to the 7.50% Notes of approximately $5.6 million ($4.1 million, net of amortization as of September 30, 2015) are being amortized over the term of the notes using the effective interest rate method.

At any time prior to August 1, 2016, we may redeem up to 35 percent of the aggregate principal amount of the 7.50% Notes at a redemption price of 107.50 percent of the principal amount, plus accrued and unpaid interest to the redemption date, with the net cash proceeds of certain equity offerings by us. On and after August 1, 2016, we may redeem all or a part of the 7.50% Notes upon appropriate notice, at a redemption price of 103.750 percent of the principal amount, and at redemption prices decreasing each year thereafter to par beginning August 1, 2018. If we experience certain changes in control, we must offer to repurchase the 7.50% Notes at 101.0 percent of the aggregate principal amount, plus accrued and unpaid interest and additional interest, if any, to the date of repurchase.

9.125% Senior Notes, due April 2018

On March 22, 2010, we issued $300.0 million aggregate principal amount of the 9.125% Notes and on April 25, 2012, we issued an additional $125.0 million aggregate principal amount of 9.125% Notes.

On January 7, 2014, we commenced a tender and consent solicitation with respect to the 9.125% Notes. The tender offer price was $1,061.98, inclusive of a $30.00 consent payment for each $1,000 principal amount of 9.125% Notes, plus accrued and unpaid interest. On January 22, 2014, we paid $453.7 million for the tendered 9.125% Notes, comprised of $416.2 million of aggregate principal amount of the 9.125% Notes, $25.8 million of tender and consent premiums and $11.7 million of accrued interest. On April 1, 2014, we redeemed the remaining $8.8 million aggregate principal amount of the outstanding 9.125% Notes for a purchase price of $9.6 million, inclusive of a $0.4 million call premium and $0.4 million of interest. During the year ended December 31, 2014, we recorded a loss on extinguishment of debt of approximately $30.2 million, which included the tender and consent premiums of $25.8 million, the call premium of $0.4 million and the write-off of unamortized debt issuance costs of $7.7 million, partially offset by the write-off of the remaining unamortized debt issuance premium of $3.8 million.

2015 Secured Credit Agreement

On January 26, 2015 we entered into the 2015 Secured Credit Agreement, which amended and restated the 2012 Secured Credit Agreement. The 2015 Secured Credit Agreement is comprised of a $200.0 million revolving credit facility (2015 Revolver) and matures on January 26, 2020. At the closing of the 2015 Secured Credit Agreement, we repaid the outstanding $30.0 million of Term Loan borrowings under the 2012 Secured Credit Agreement with a $30.0 million draw on the 2015 Revolver. On June 1, 2015, we executed the first amendment to the 2015 Secured Credit Agreement in order to amend certain provisions of the 2015 Secured Credit Agreement regarding the definition of “Change of Control.” On September 29, 2015, we executed the second amendment to the 2015 Secured Credit Agreement (the “Second Amendment”). Among other things, the Second Amendment: (a) gradually increases the permissible consolidated leverage ratio from a maximum of 4.00:1.00 to 5.75:1.00 through December 31, 2016, which thereafter gradually reduces to 4.00:1.00 by December 31, 2017; (b) reduces the consolidated interest coverage ratio from 2.50:1:00 to 2.25:1.00 for each quarter of 2016, and returning to 2.50:1.00 thereafter; (c) increases the Applicable Rate for certain higher levels of consolidated leverage to a maximum of 4.00 percent per annum for LIBOR rate loans and to 3.00 percent per annum for base rate loans; (d) allows multi-year letters of credit up to an aggregate amount of $5 million; (e) limits payment prior to September 30, 2017 of certain restricted payments and certain prepayments of unsecured senior notes and other specified forms of indebtedness; and (f) removes the option of Company, subject to the consent of the lenders, to increase the Credit Agreement up to an additional $75 million. We incurred debt issuance costs related to the 2015 Secured Credit Agreement of approximately $2.0 million and had approximately $0.8 million of remaining debt issuance costs for the 2012 Secured Credit agreement. The total debt issuance costs of $2.8 million ($2.6 million, net of amortization as of September 30, 2015) are being amortized over the term of the 2015 Secured Credit Agreement on a straight line basis.

Our obligations under the 2015 Secured Credit Agreement are guaranteed by substantially all of our direct and indirect domestic subsidiaries, other than immaterial subsidiaries and subsidiaries generating revenues primarily outside the United States, each of which has executed guaranty agreements, and are secured by first priority liens on our accounts receivable, specified rigs including barge rigs in the GOM and land rigs in Alaska, and certain U.S.-based rental equipment of the Company and its subsidiary guarantors. The 2015 Secured Credit Agreement contains customary affirmative and negative covenants, such as limitations on indebtedness, liens, restrictions on entry into certain affiliate transactions and payments (including payment of dividends) and maintenance of certain ratios and coverage tests (including a minimum asset coverage ratio of 1.25:1.00 at each quarter end). We were in compliance with all such covenants as of September 30, 2015.

Our 2015 Revolver is available for general corporate purposes and to support letters of credit. Interest on 2015 Revolver loans accrues at a Base Rate plus an Applicable Rate or LIBOR plus an Applicable Rate. As a result of the Second Amendment, the Applicable Rate ranges from 2.50 percent to 4.00 percent per annum for LIBOR rate loans and from 1.50 percent to 3.00 percent per annum for base rate loans, determined by reference to the consolidated leverage ratio (as defined in the 2015 Secured Credit Agreement). Revolving loans are available subject to a quarterly Asset Coverage Ratio calculation based on the Orderly Liquidation Value of certain specified rigs including barge rigs in the GOM and land rigs in Alaska, and certain U.S.-based rental equipment of the Company and its subsidiary guarantors and a percentage of eligible domestic accounts receivable. The $30.0 million draw at the closing of the 2015 Secured Credit Agreement was repaid in full during the first quarter of 2015 with cash on hand. Letters of credit outstanding against the 2015 Revolver as of September 30, 2015 totaled $13.8 million. There were no amounts drawn on the 2015 Revolver as of September 30, 2015.

2012 Secured Credit Agreement

The 2012 Secured Credit Agreement consisted of an $80.0 million revolving credit facility (2012 Revolver) and a $50.0 million term loan (Term Loan). Our obligations under the 2012 Secured Credit Agreement were 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 had executed guaranty agreements, and were secured by first priority liens on our accounts receivable, specified barge rigs and rental equipment. The 2012 Secured Credit Agreement contained customary affirmative and negative covenants and would have matured on December 14, 2017.

2012 Revolver

Our 2012 Revolver was available for general corporate purposes and to support letters of credit. Interest on 2012 Revolver loans accrued at a Base Rate plus an Applicable Rate or LIBOR plus an Applicable Rate. Under the 2012 Secured Credit Agreement, the Applicable Rate ranged from 2.50 percent to 3.00 percent per annum for LIBOR rate loans and from 1.50 percent to 2.00 percent per annum for base rate loans, determined by reference to the consolidated leverage ratio (as defined in the 2012 Secured Credit Agreement). Revolving loans were available subject to a borrowing base calculation based on a percentage of eligible accounts receivable, certain specified barge drilling rigs and rental equipment of the Company and its subsidiary guarantors. There were no revolving loans outstanding at December 31, 2014. Letters of credit outstanding against the 2012 Revolver as of December 31, 2014 totaled $11.0 million.

Term Loan

The Term Loan originated at $50.0 million on December 14, 2012 and required quarterly principal payments of $2.5 million, which began March 31, 2013. Interest on the Term Loan accrued at a Base Rate plus 2.00 percent or LIBOR plus 3.00 percent. In July 2013, we repaid the outstanding balance of $45.0 million of the Term Loan and amended the 2012 Secured Credit Agreement to permit re-borrowing of up to $45.0 million of the Term Loan, decreasing by $2.5 million at the end of each quarter beginning September 30, 2013 and ending March 31, 2014. In January 2014 we re-borrowed $40.0 million of the Term Loan. The outstanding balance on the Term Loan at December 31, 2014 was $30.0 million. At the closing of the 2015 Secured Credit Agreement, we repaid the Term Loan with a $30.0 million draw under the 2015 Revolver.

Note 11 - Fair Value of Financial Instruments

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

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


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


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


•	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:



	September 30, 2015				December 31, 2014
Dollars in thousands	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term Debt
6.75% Notes	$	360,000	$	285,300	$	360,000	$	270,000
7.50% Notes	225,000		187,313		225,000		180,000
Total	$	585,000	$	472,613	$	585,000	$	450,000

Market conditions could cause an instrument to be reclassified from Level 1 to Level 2, or Level 2 to Level 3. There were no transfers between levels of the fair value hierarchy or any changes in the valuation techniques used during the nine months ended September 30, 2015.

Note 12 - Commitments and Contingencies

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

Customs Agent and Foreign Corrupt Practices Act (FCPA) Settlement

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

Note 13 - Recent Accounting Pronouncements

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

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

In June 2015, the FASB issued ASU No. 2015-10, Technical Corrections and Improvements, which contains amendments that will affect a wide variety of topics in the Codification. The amendments in this Update will apply to all reporting entities within the scope of the affected accounting guidance. Transition guidance varies based on the amendments in the Update. The amendments in the Update that require transition guidance are effective for all entities for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. Early adoption is permitted, including adoption in an interim period. All other amendments will be effective upon the issuance of this Update. We plan to adopt the standard and are in the process of assessing the impact of the adoption of ASU 2015-10 on our financial position, results of operations and cash flows.

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

On May 28, 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers. This ASU supersedes the revenue recognition requirements in Accounting Standards Codification 605 - Revenue Recognition and most industry-specific guidance throughout the Codification. The standard requires that an entity recognizes revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services and should be applied retrospectively to each prior reporting period presented or retrospectively with the cumulative effect of initially applying the ASU recognized at the date of initial application. ASU 2014-09 was initially scheduled to be effective for the first quarter of 2017, however, on April 1, 2015, the FASB proposed to defer the effective date by one year and the proposal was accepted during the second quarter of 2015. ASU 2014-09 is now scheduled to be effective for entities beginning after December 15, 2017. We are in the process of assessing the impact of the adoption of ASU 2014-09 on our financial position, results of operations and cash flows. We have not yet selected a transition method nor have we determined the effect of the standard on our ongoing financial reporting.

Note 14 - Parent, Guarantor, Non-Guarantor Unaudited Consolidating Condensed Financial Statements

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


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


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


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


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


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

There are currently no restrictions on the ability of the restricted subsidiaries to transfer funds to Parker Drilling in the form of cash dividends, loans or advances. Parker Drilling is a holding company with no operations, other than through its subsidiaries. Separate financial statements for each guarantor company are not provided as the Company complies with the exception to Rule 3-10(a)(1) of Regulation S-X, set forth in sub-paragraph (f) of such rule. All guarantor subsidiaries are owned 100 percent by the parent company.

We are providing unaudited consolidating condensed financial information of the parent, Parker Drilling, the guarantor subsidiaries, and the non-guarantor subsidiaries as of September 30, 2015 and December 31, 2014 and for the three and nine months ended September 30, 2015 and 2014, respectively. The consolidating condensed financial statements present investments in both consolidated and unconsolidated subsidiaries using the equity method of accounting.

Upon the closing of our 2015 Secured Credit Agreement, one of our subsidiaries was released as a guarantor subsidiary and is now classified as a non-guarantor subsidiary. In accordance with the guidance Topic No. 810, Consolidation (ASC 810), we have retrospectively updated the unaudited consolidating condensed financial information as of December 31, 2014 and for the three and nine months ended September 30, 2014.

PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATING CONDENSED BALANCE SHEET

(Dollars in Thousands)

(Unaudited)



	September 30, 2015
	Parent			Guarantor			Non-Guarantor			Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	46,528		$	8,000		$	50,123		$	—		$	104,651
Accounts and notes receivable, net	—			66,413			158,583			—			224,996
Rig materials and supplies	—			(4,279		)	42,795			—			38,516
Deferred costs	—			—			2,961			—			2,961
Deferred income taxes	—			4,172			1,276			—			5,448
Other tax assets	—			463			7,369			—			7,832
Other current assets	—			6,717			10,484			—			17,201
Total current assets	46,528			81,486			273,591			—			401,605
Property, plant and equipment, net	(19		)	560,618			281,324			—			841,923
Goodwill	—			6,708			—			—			6,708
Intangible assets, net	—			12,317			2,424			—			14,741
Investment in subsidiaries and intercompany advances	3,074,849			2,700,571			3,147,601			(8,923,021		)	—
Other noncurrent assets	(276,366		)	374,987			246,033			(167,448		)	177,206
Total assets	$	2,844,992		$	3,736,687		$	3,950,973		$	(9,090,469	)	$	1,442,183

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Current portion of long-term debt	$	—		$	—		$	—		$	—		$	—
Accounts payable and accrued liabilities	67,123			77,565			303,001			(304,113		)	143,576
Accrued income taxes	1,013			9,434			(3,853		)	—			6,594
Total current liabilities	68,136			86,999			299,148			(304,113		)	150,170
Long-term debt	585,000			—			—			—			585,000
Other long-term liabilities	2,867			8,004			9,270			—			20,141
Long-term deferred tax liability	—			75,545			(348		)	—			75,197
Intercompany payables	1,581,364			1,395,937			1,711,311			(4,688,612		)	—
Total liabilities	2,237,367			1,566,485			2,019,381			(4,992,725		)	830,508
Total equity	607,625			2,170,202			1,931,592			(4,097,744		)	611,675
Total liabilities and stockholders’ equity	$	2,844,992		$	3,736,687		$	3,950,973		$	(9,090,469	)	$	1,442,183

PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATING CONDENSED BALANCE SHEET

(Dollars in Thousands)

(Unaudited)



	December 31, 2014
	Parent			Guarantor			Non-Guarantor			Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	36,728		$	13,546		$	58,182		$	—		$	108,456
Accounts and notes receivable, net	(33		)	96,100			174,885			—			270,952
Rig materials and supplies	—			(1,473		)	49,416			—			47,943
Deferred costs	—			—			5,673			—			5,673
Deferred income taxes	—			6,131			1,345			—			7,476
Other tax assets	19,885			(18,273		)	9,111			—			10,723
Other current assets	—			7,998			10,558			—			18,556
Total current assets	56,580			104,029			309,170			—			469,779
Property, plant and equipment, net	(19		)	589,055			306,904			—			895,940
Intangible assets, net	—			—			4,286			—			4,286
Investment in subsidiaries and intercompany advances	3,060,867			2,441,523			2,464,506			(7,966,896		)	—
Other noncurrent assets	(440,918		)	490,597			268,537			(167,562		)	150,654
Total assets	$	2,676,510		$	3,625,204		$	3,353,403		$	(8,134,458	)	$	1,520,659
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Current portion of long-term debt	$	10,000		$	—		$	—		$	—		$	10,000
Accounts payable and accrued liabilities	77,603			71,645			309,344			(304,113		)	154,479
Accrued income taxes	(4,061		)	10,109			8,138			—			14,186
Total current liabilities	83,542			81,754			317,482			(304,113		)	178,665
Long-term debt	605,000			—			—			—			605,000
Other long-term liabilities	2,867			7,135			8,663			—			18,665
Long-term deferred tax liability	—			56,105			(3,990		)	—			52,115
Intercompany payables	1,322,172			1,311,404			1,204,769			(3,838,345		)	—
Total liabilities	2,013,581			1,456,398			1,526,924			(4,142,458		)	854,445
Total equity	662,929			2,168,806			1,826,479			(3,992,000		)	666,214
Total liabilities and stockholders’ equity	$	2,676,510		$	3,625,204		$	3,353,403		$	(8,134,458	)	$	1,520,659

PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATING CONDENSED STATEMENT OF OPERATIONS

(Dollars in Thousands)

(Unaudited)



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

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

PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATING CONDENSED STATEMENT OF OPERATIONS

(Dollars in Thousands)

(Unaudited)



	Three Months Ended September 30, 2014
	Parent			Guarantor			Non-Guarantor			Eliminations			Consolidated
Total revenues	$	—		$	129,935		$	156,495		$	(44,418	)	$	242,012
Operating expenses	—			65,369			139,846			(44,418		)	160,797
Depreciation and amortization	—			22,168			13,981			—			36,149
Total operating gross margin	—			42,398			2,668			—			45,066
General and administration expense ⁽¹⁾	110			(8,988		)	(492		)	—			(9,370		)
Gain (loss) on disposition of assets, net	—			91			(548		)	—			(457		)
Total operating income (loss)	110			33,501			1,628			—			35,239
Other income and (expense):
Interest expense	(11,529		)	(35		)	(1,943		)	2,659			(10,848		)
Interest income	98			176			2,421			(2,659		)	36
Other	—			675			(1,211		)	—			(536		)
Equity in net earnings of subsidiaries	19,442			—			—			(19,442		)	—
Total other income (expense)	8,011			816			(733		)	(19,442		)	(11,348		)
Income (loss) before income taxes	8,121			34,317			895			(19,442		)	23,891
Income tax expense (benefit)	(4,445		)	14,337			1,122			—			11,014
Net income (loss)	12,566			19,980			(227		)	(19,442		)	12,877
Less: Net income attributable to noncontrolling interest	—			—			311			—			311
Net income (loss) attributable to controlling interest	$	12,566		$	19,980		$	(538	)	$	(19,442	)	$	12,566

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

PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATING CONDENSED STATEMENT OF OPERATIONS

(Dollars in Thousands)

(Unaudited)



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

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

PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATING CONDENSED STATEMENT OF OPERATIONS

(Dollars in Thousands)

(Unaudited)



	Nine Months Ended September 30, 2014
	Parent			Guarantor			Non-Guarantor			Eliminations			Consolidated
Total revenues	$	—		$	396,536		$	461,460		$	(132,525	)	$	725,471
Operating expenses	—			222,846			411,070			(132,525		)	501,391
Depreciation and amortization	—			63,343			43,323			—			106,666
Total operating gross margin	—			110,347			7,067			—			117,414
General and administration expense ⁽¹⁾	(195		)	(23,806		)	(1,340		)	—			(25,341		)
Gain (loss) on disposition of assets, net	(79		)	522			(10		)	—			433
Total operating income (loss)	(274		)	87,063			5,717			—			92,506
Other income and (expense):
Interest expense	(35,542		)	(120		)	(6,356		)	8,532			(33,486		)
Interest income	632			553			7,503			(8,532		)	156
Extinguishment of debt	(30,152		)	—			—			—			(30,152		)
Other	—			860			531			—			1,391
Equity in net earnings of subsidiaries	50,591			—			—			(50,591		)	—
Total other income (expense)	(14,471		)	1,293			1,678			(50,591		)	(62,091		)
Income (loss) before income taxes	(14,745		)	88,356			7,395			(50,591		)	30,415
Total income tax expense (benefit)	(30,443		)	34,187			10,349			—			14,093
Net income (loss)	15,698			54,169			(2,954		)	(50,591		)	16,322
Less: Net income attributable to noncontrolling interest	—			—			624			—			624
Net income (loss) attributable to controlling interest	$	15,698		$	54,169		$	(3,578	)	$	(50,591	)	$	15,698

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

PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATING CONDENSED STATEMENT OF COMPREHENSIVE INCOME (LOSS)

(Dollars in Thousands)

(Unaudited)



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

PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATING CONDENSED STATEMENT OF COMPREHENSIVE INCOME (LOSS)

(Dollars in Thousands)

(Unaudited)



	Three Months Ended September 30, 2014
	Parent		Guarantor		Non-Guarantor			Eliminations			Consolidated
Comprehensive income:
Net income (loss)	$	12,566	$	19,980	$	(227	)	$	(19,442	)	$	12,877
Other comprehensive income (loss), net of tax:
Currency translation difference on related borrowings	—		—		(1,780		)	—			(1,780		)
Currency translation difference on foreign currency net investments	—		—		615			—			615
Total other comprehensive income (loss), net of tax:	—		—		(1,165		)	—			(1,165		)
Comprehensive income (loss)	12,566		19,980		(1,392		)	(19,442		)	11,712
Comprehensive (loss) attributable to noncontrolling interest	—		—		(289		)	—			(289		)
Comprehensive income (loss) attributable to controlling interest	$	12,566	$	19,980	$	(1,681	)	$	(19,442	)	$	11,423

PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATING CONDENSED STATEMENT OF COMPREHENSIVE INCOME (LOSS)

(Dollars in Thousands)

(Unaudited)



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

PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATING CONDENSED STATEMENT OF COMPREHENSIVE INCOME (LOSS)

(Dollars in Thousands)

(Unaudited)



	Nine Months Ended September 30, 2014
	Parent		Guarantor		Non-Guarantor			Eliminations			Consolidated
Comprehensive income:
Net income (loss)	$	15,698	$	54,169	$	(2,954	)	$	(50,591	)	$	16,322
Other comprehensive income (loss), net of tax:
Currency translation difference on related borrowings	—		—		(2,248		)	—			(2,248		)
Currency translation difference on foreign currency net investments	—		—		1,126			—			1,126
Total other comprehensive income (loss), net of tax:	—		—		(1,122		)	—			(1,122		)
Comprehensive income (loss)	15,698		54,169		(4,076		)	(50,591		)	15,200
Comprehensive (loss) attributable to noncontrolling interest	—		—		(523		)	—			(523		)
Comprehensive income (loss) attributable to controlling interest	$	15,698	$	54,169	$	(4,599	)	$	(50,591	)	$	14,677

PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)

(Unaudited)



	Nine Months Ended September 30, 2015
	Parent			Guarantor			Non-Guarantor			Eliminations			Consolidated
Cash flows from operating activities:
Net income (loss)	$	(59,427	)	$	(8,984	)	$	(19,543	)	$	29,316		$	(58,638	)
Adjustments to reconcile net income (loss):
Depreciation and amortization	—			71,270			47,204			—			118,474
Accretion of contingent consideration	—			—			547			—			547
Provision for reduction in carrying value of certain assets	—			920			2,302			—			3,222
Gain on disposition of assets	—			(452		)	(2,234		)	—			(2,686		)
Deferred income tax expense	(24,184		)	10,032			24,411			—			10,259
Expenses not requiring cash	6,498			2,677			(1,146		)	—			8,029
Equity in net earnings of subsidiaries	29,316			—			—			(29,316		)	—
Change in assets and liabilities:
Accounts and notes receivable	(33		)	36,694			14,593			—			51,254
Other assets	(121,465		)	110,017			12,934			—			1,486
Accounts payable and accrued liabilities	(10,480		)	(168		)	(5,142		)	—			(15,790		)
Accrued income taxes	6,481			(2,081		)	(11,705		)	—			(7,305		)
Net cash provided by (used in) operating activities	(173,294		)	219,925			62,221			—			108,852

Cash flows from investing activities:
Capital expenditures	—			(50,396		)	(22,073		)	—			(72,469		)
Proceeds from the sale of assets	—			489			242			—			731
Proceeds from insurance settlements	—			—			2,500			—			2,500
Acquisition, net of cash acquired	—			(10,431		)	—			—			(10,431		)
Net cash (used in) investing activities	—			(60,338		)	(19,331		)	—			(79,669		)

Cash flows from financing activities:
Repayments of long-term debt	(30,000		)	—			—			—			(30,000		)
Payment of debt issuance costs	(1,996		)	—			—			—			(1,996		)
Excess tax benefit from stock-based compensation	(992		)	—			—			—			(992		)
Intercompany advances, net	216,082			(165,133		)	(50,949		)	—			—
Net cash provided by (used in) financing activities	183,094			(165,133		)	(50,949		)	—			(32,988		)

Net change in cash and cash equivalents	9,800			(5,546		)	(8,059		)	—			(3,805		)
Cash and cash equivalents at beginning of year	36,728			13,546			58,182			—			108,456
Cash and cash equivalents at end of year	$	46,528		$	8,000		$	50,123		$	—		$	104,651

PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)

(Unaudited)



	Nine Months Ended September 30, 2014
	Parent			Guarantor			Non-Guarantor			Eliminations			Consolidated
Cash flows from operating activities:
Net income (loss)	$	15,698		$	54,169		$	(2,954	)	$	(50,591	)	$	16,322
Adjustments to reconcile net income (loss)
Depreciation and amortization	—			63,343			43,323			—			106,666
Loss on extinguishment of debt	30,152			—			—			—			30,152
Gain on disposition of assets	79			(522		)	10			—			(433		)
Deferred income tax expense	(15,774		)	12,525			3,322			—			73
Expenses not requiring cash	9,940			(1,538		)	1,739			—			10,141
Equity in net earnings of subsidiaries	(50,591		)	—			—			50,591			—
Change in assets and liabilities:
Accounts and notes receivable	—			(1,715		)	(3,473		)	—			(5,188		)
Other assets	43,412			(58,441		)	22,583			—			7,554
Accounts payable and accrued liabilities	(8,213		)	(9,395		)	7,069			—			(10,539		)
Accrued income taxes	(13,232		)	11,764			(8,929		)	—			(10,397		)
Net cash provided by (used in) operating activities	11,471			70,190			62,690			—			144,351

Cash flows from investing activities:
Capital expenditures	—			(107,137		)	(43,972		)	—			(151,109		)
Proceeds from the sale of assets	—			1,088			1,206			—			2,294
Net cash (used in) investing activities	—			(106,049		)	(42,766		)	—			(148,815		)

Cash flows from financing activities:
Proceeds from debt issuance	400,000			—			—			—			400,000
Repayments of long-term debt	(432,500		)	—			—			—			(432,500		)
Payment of debt issuance costs	(7,630		)	—			—			—			(7,630		)
Payment of debt extinguishment costs	(26,214		)	—			—			—			(26,214		)
Excess tax benefit from stock-based compensation	430			—			—			—			430
Intercompany advances, net	(10,677		)	40,064			(29,387		)	—			—
Net cash provided by (used in) financing activities	(76,591		)	40,064			(29,387		)	—			(65,914		)

Net change in cash and cash equivalents	(65,120		)	4,205			(9,463		)	—			(70,378		)
Cash and cash equivalents at beginning of year	88,697			8,310			51,682			—			148,689
Cash and cash equivalents at end of year	$	23,577		$	12,515		$	42,219		$	—		$	78,311

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

Management's discussion and analysis (MD&A) should be read in conjunction with Item 1. Financial Statements.

DISCLOSURE NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Form 10-Q contains statements that are “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (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, including any statements regarding:

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

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

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

•our future operating results and profitability;

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


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

•continuation of existing contracts for drilling services and rental tools services for their stated duration and rate;

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

•growth through acquisitions of companies or assets;

•organic growth of our operations;

•construction or upgrades of rigs and expectations regarding when these rigs will commence operations;

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

•entering into joint venture agreements;

•our future liquidity;

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

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

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

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

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

•compliance with covenants under our debt agreements.

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


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


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


•	our inability to access the credit markets and U.S. credit market volatility;

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


•	low U.S. oil and natural gas prices that could adversely affect our U.S. drilling services, barge rig and U.S. rental tools services businesses;

•worldwide demand for oil;


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

•unanticipated operating hazards and uninsured risks;

•political instability, terrorism or war;


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

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

•the outcome of investigations into possible violations of laws;

•adverse environmental events;

•adverse weather conditions;

•global health concerns;

•changes in the concentration of customer and supplier relationships;

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

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


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

•shortages of skilled labor;

•unanticipated cancellation of contracts by customers or operators;

•breakdown of equipment;


•	other operational challenges including our ability to effectively reactivate stacked rigs and delays in start-up or commissioning of rigs;


•	the inability to obtain, or delays in obtaining, licenses and permits necessary to operate, move or transport our rigs, rig components, rental tools and related equipment;

•the inability to access or restrictions on access to our rigs, field locations and other facilities;

•changes in competition;

•any failure to realize expected benefits from acquisitions;

•the effect of litigation and contingencies; and


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

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

Executive Overview and Outlook

Oil prices have declined significantly since late 2014, resulting in curtailed spending and operations on the part of oil and gas producers, particularly our customers in the U.S. As a result, our customers across most geographic regions have reduced their capital spending, terminated certain drilling contracts, requested pricing concessions and taken other measures aimed at reducing the capital and operating expenses within their supply chain. This has adversely impacted our rental tools activity and pricing, as well as utilization and pricing of our drilling rigs. While our U.S.-based businesses have been significantly impacted, we have also experienced lower pricing and utilization of tools, services and rigs in certain international markets.

Although the severity and duration of the current industry downturn is contingent upon many factors beyond our control, we have taken several steps in an effort to generate free cash flow during this period, including lowering our cost base through headcount reductions and lower idle rig costs, maintaining our working capital diligence, reducing capital expenditures and striving to sustain utilization and market share.

For the three months ended September 30, 2015, our revenues were $173.4 million and our net loss was $48.6 million, or $0.40 per share. Of this amount, $36.6 million, or $0.30 per diluted share, is income tax expense we recognized as a result of recording a valuation allowance primarily on U.S. foreign tax credits and certain foreign net operating losses.

Third quarter 2015 revenues in our U.S. (Lower 48) Drilling segment decreased 11.8 percent sequentially to $6.0 million, as compared with $6.8 million in the second quarter of 2015. Gross margin was a $1.9 million loss as compared with 2015 second quarter gross margin loss of $2.0 million. The decline in revenues was primarily the result of lower O&M activity in California, while gross margin improved as a result of slightly higher utilization and lower costs in the Gulf of Mexico (GOM) barge drilling operation.

Third quarter 2015 revenues in our International & Alaska Drilling segment decreased 3.7 percent sequentially to $110.7 million, as compared with $115.0 million in the 2015 second quarter. Gross margin was $29.1 million, a 28.8 percent increase from 2015 second quarter gross margin of $22.6 million. Gross margin as a percentage of revenues was 26.3 percent as compared with 19.7 percent in the 2015 second quarter. The decrease in revenues is attributable to a $7.1 million decrease in reimbursable expenses and lower Eastern Hemisphere rig utilization, partially offset by an increase in Latin America utilization and increased revenues from our project service activities. The increase in gross margin as a percentage of revenues is due to lower revenues from reimbursable expenses, higher utilization in Latin America, lower operating expenses in certain locations and higher margins earned on project services activities.

Third quarter 2015 revenues in our Rental Tools Services segment decreased 11.4 percent to $56.8 million, as compared with $64.1 million in the 2015 second quarter. Gross margin was $17.2 million and gross margin as a percentage of revenues was 30.3 percent. Compared with the 2015 second quarter, gross margin decreased 20.7 percent from $21.7 million, while gross margin as a percentage of revenues decreased from 33.9 percent. Reduced revenues and gross margin were primarily due to the continued decline in U.S. land drilling activity, as well as lower pricing and business mix in certain international rental tools markets.

We believe overall energy market conditions will remain at low levels for the remainder of the year, and possibly, throughout 2016, due to the ongoing imbalance in oil supply and demand. We believe these conditions will continue to cause our customers to curtail spending and activity levels. We have taken steps to align resources with the ongoing market downturn, and will continue to adjust and adapt to the business environment and market conditions, while remaining opportunistic and positioning the Company for longer-term growth.

Results of Operations

We analyze financial results for each of our reportable segments. The reportable segments presented are consistent with our reportable segments discussed in Note 7 of our consolidated condensed consolidated 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 U.S. GAAP, but should be viewed in addition to the Company’s reported results prepared in accordance with GAAP. Management believes this information may provide users of this financial information additional meaningful comparisons between current results and results of prior periods.

Three Months Ended September 30, 2015 Compared with Three Months Ended September 30, 2014

Revenues of $173.4 million for the three months ended September 30, 2015 decreased $68.6 million, or 28.3 percent, compared with $242.0 million for the three months ended September 30, 2014. Operating gross margin decreased $40.2 million, or 89.1 percent, to $4.9 million, for the three months ended September 30, 2015 compared with $45.1 million for the three months ended September 30, 2014.

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



	Three Months Ended September 30,
Dollars in Thousands	2015					2014
Revenues:
Drilling Services:
U.S. (Lower 48) Drilling	$	5,961		3	%	$	44,409		18	%
International & Alaska Drilling	110,661			64	%	109,892			45	%
Total Drilling Services	116,622			67	%	154,301			63	%
Rental Tools	56,796			33	%	87,711			37	%
Total revenues	173,418			100	%	242,012			100	%
Operating gross margin excluding depreciation and amortization:
Drilling Services:
U.S. (Lower 48) Drilling	(1,859		)	(31	)%	21,722			49	%
International & Alaska Drilling	29,075			26	%	23,769			22	%
Total Drilling Services	27,216			23	%	45,491			29	%
Rental Tools	17,239			30	%	35,724			41	%
Total operating gross margin excluding depreciation and amortization	44,455			26	%	81,215			34	%
Depreciation and amortization	(39,584		)			(36,149		)
Total operating gross margin	4,871					45,066
General and administrative expense	(8,895		)			(9,370		)
Provision for reduction in carrying value of certain assets	(906		)			—
Gain (loss) on disposition of assets, net	383					(457		)
Total operating income (loss)	$	(4,547	)			$	35,239

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



Dollars in Thousands	U.S. (Lower 48) Drilling			International & Alaska Drilling		Rental Tools			Total
Three Months Ended September 30, 2015
Operating gross margin ⁽¹⁾	$	(7,397	)	$	13,212	$	(944	)	$	4,871
Depreciation and amortization	5,538			15,863		18,183			39,584
Operating gross margin excluding depreciation and amortization	$	(1,859	)	$	29,075	$	17,239		$	44,455
Three Months Ended September 30, 2014
Operating gross margin ⁽¹⁾	$	16,283		$	9,131	$	19,652		$	45,066
Depreciation and amortization	5,439			14,638		16,072			36,149
Operating gross margin excluding depreciation and amortization	$	21,722		$	23,769	$	35,724		$	81,215


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

The following table presents our average utilization rates and rigs available for service for the three months ended September 30, 2015 and 2014, respectively:.



	Three Months Ended September 30,
	2015		2014
U.S. (Lower 48) Drilling
Rigs available for service ⁽¹⁾	13.0		12.7
Utilization rate of rigs available for service ⁽²⁾	16	%	75	%
International & Alaska Drilling
Eastern Hemisphere
Rigs available for service ⁽¹⁾	13.0		13.0
Utilization rate of rigs available for service ⁽²⁾	59	%	77	%
Latin America Region
Rigs available for service ⁽¹⁾	9.0		9.0
Utilization rate of rigs available for service ⁽²⁾	44	%	55	%
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⁾	24.0		24.0
Utilization rate of rigs available for service ⁽²⁾	57	%	71	%

(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 Line

U.S. (Lower 48) Drilling

U.S. (Lower 48) Drilling segment revenues decreased $38.4 million, or 86.5 percent, to $6.0 million for the third quarter of 2015 compared with $44.4 million for the third quarter of 2014. The decrease in revenues was primarily due to lower utilization and a decline in average dayrates for the barge drilling business resulting from substantial reductions in drilling activity by operators in the inland waters of the GOM in response to lower oil prices.

U.S. (Lower 48) Drilling segment's operating gross margin excluding depreciation and amortization decreased $23.6 million to a loss of $1.9 million for the third quarter of 2015 compared with income of $21.7 million for the third quarter of 2014. The decrease was primarily due to the decline in utilization and average dayrates discussed above.

International & Alaska Drilling

International & Alaska Drilling segment revenues increased $0.8 million, or 0.7 percent, to $110.7 million for the third quarter of 2015 compared with $109.9 million for the third quarter of 2014. The increase in segment revenues was driven by higher reimbursable expenses for our Sakhalin Island O&M operations, contributions from a two-rig O&M contract in Abu Dhabi that commenced during the 2015 first quarter, and increased revenues from our project services activities. The increase in revenues was partially offset by a reduced dayrate for our Sakhalin Island drilling operation as the company-owned rig has been on a reduced standby rate since November 2014, and reduced utilization in our Eastern Hemisphere region. Revenues from our Latin America region were relatively flat for the 2015 third quarter compared to the 2014 third quarter. Approximately $20.7 million and $17.7 million of total segment revenues were attributable to reimbursable costs for the three month periods ended September 30, 2015 and 2014, respectively, which increased revenues, but had minimal impact on operating margins.

International & Alaska Drilling segment operating gross margin excluding depreciation and amortization increased $5.3 million, or 22.3 percent, to $29.1 million for the third quarter of 2015 compared with $23.8 million for the third quarter of 2014. The increase in operating gross margin excluding depreciation and amortization was primarily due to higher margins earned on our project services activities described above and the benefit of lower operating costs in our Latin America region. The increase was partially offset by lower utilization in our Eastern Hemisphere region.

Rental Tools Services Business Line

Rental Tools segment revenues decreased $30.9 million, or 35.2 percent, to $56.8 million for the third quarter of 2015 compared with $87.7 million for the third quarter of 2014. The decrease was primarily due to reduced customer activity resulting from lower oil prices. Additionally, we experienced lower pricing and activity in certain international rental tools markets.

Rental Tools segment operating gross margin excluding depreciation and amortization decreased $18.5 million, or 51.8 percent, to $17.2 million in the third quarter of 2015 compared with $35.7 million for the third quarter of 2014. The decrease in operating gross margin excluding depreciation and amortization is primarily due to the decline in our U.S. operations discussed above.

Other Financial Data

General and administrative expense

General and administration expense decreased $0.5 million to $8.9 million for the third quarter of 2015 compared with $9.4 million for the third quarter of 2014. General and administrative expense in the third quarter of 2014 benefited from a $1.25 million reimbursement received from an escrow account related to the ITS Acquisition. General and administrative expense in the third quarter of 2015 benefited from cost savings initiatives.

Provision for reduction in carrying value of certain assets

During the third quarter of 2015, we recorded a $0.9 million provision for reduction in carrying value related to certain assets in our International & Alaska Drilling segment. Management concluded that due to changing market conditions the carrying value of the assets is no longer recoverable.

Gain/loss on disposition of assets

Net gains recognized on asset dispositions were $0.4 million during the third quarter of 2015 compared with net losses of $0.5 million during the third quarter of 2014. We periodically sell equipment deemed to be excess, obsolete, or not currently required for operations.

Interest income and expense

Interest expense increased $0.5 million to $11.3 million for the third quarter of 2015 compared with $10.8 million for the third quarter of 2014. During the 2015 first quarter, we increased the revolving credit capacity under our 2015 Secured Credit Agreement from $80 million to $200 million which resulted in higher fees on the unused portion of the 2015 Revolver. Interest income during each of the 2015 and 2014 third quarters was nominal.

Other income and expense

We incurred $0.7 million of other expense for the third quarter of 2015 compared with $0.5 million of other expense for the third quarter of 2014. Other expense for the third quarter of 2015 was primarily driven by losses related to foreign currency fluctuations. Other expense for the third quarter of 2014 was primarily driven by a settlement of claims against a vendor, offset by losses related to foreign currency fluctuations.

Income tax expense (benefit)

Nine Months Ended September 30, 2015 Compared with Nine Months Ended September 30, 2014

Revenues of $563.4 million for the nine months ended September 30, 2015 decreased $162.1 million, or 22.3 percent, compared with $725.5 million for the nine months ended September 30, 2014. Operating gross margin decreased $84.2 million, or 71.7 percent, to $33.2 million, for the nine months ended September 30, 2015 compared with $117.4 million for the nine months ended September 30, 2014.

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



	Nine Months Ended September 30,
Dollars in Thousands	2015					2014
Revenues:
Drilling Services:
U.S. (Lower 48) Drilling	$	26,906		5	%	$	126,281		17	%
International & Alaska Drilling	339,551			60	%	343,803			48	%
Total Drilling Services	366,457			65	%	470,084			65	%
Rental Tools	196,978			35	%	255,387			35	%
Total revenues	563,435			100	%	725,471			100	%
Operating gross margin excluding depreciation and amortization:
Drilling Services:
U.S. (Lower 48) Drilling	(3,724		)	(14	)%	57,335			45	%
International & Alaska Drilling	87,107			26	%	68,943			20	%
Total Drilling Services	83,383			23	%	126,278			27	%
Rental Tools	68,250			35	%	97,802			38	%
Total operating gross margin excluding depreciation and amortization	151,633			27	%	224,080			31	%
Depreciation and amortization	(118,474		)			(106,666		)
Total operating gross margin	33,159					117,414
General and administrative expense	(29,243		)			(25,341		)
Provision for reduction in carrying value of certain assets	(3,222		)			—
Gain (loss) on disposition of assets, net	2,686					433
Total operating income	$	3,380				$	92,506

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



Dollars in Thousands	U.S. (Lower 48) Drilling			International & Alaska Drilling		Rental Tools		Total
Nine Months Ended September 30, 2015
Operating gross margin ⁽¹⁾	$	(20,673	)	$	37,428	$	16,404	$	33,159
Depreciation and amortization	16,949			49,679		51,846		118,474
Operating gross margin excluding depreciation and amortization	$	(3,724	)	$	87,107	$	68,250	$	151,633
Nine Months Ended September 30, 2014
Operating gross margin ⁽¹⁾	$	42,829		$	23,824	$	50,761	$	117,414
Depreciation and amortization	14,506			45,119		47,041		106,666
Operating gross margin excluding depreciation and amortization	$	57,335		$	68,943	$	97,802	$	224,080


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

The following table presents our average utilization rates and rigs available for service for the nine months ended September 30, 2015 and 2014, respectively:



	Nine Months Ended September 30,
	2015		2014
U.S. (Lower 48) Drilling
Rigs available for service (1)	13.0		11.7
Utilization rate of rigs available for service (2)	17	%	80	%
International & Alaska Drilling
Eastern Hemisphere
Rigs available for service (1)	13.0		13.0
Utilization rate of rigs available for service (2)	70	%	77	%
Latin America Region
Rigs available for service (1)	9.0		9.0
Utilization rate of rigs available for service (2)	44	%	65	%
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)	24.0		24.0
Utilization rate of rigs available for service (2)	63	%	74	%

(1)

(2)

Drilling Services Business Line

U.S. (Lower 48) Drilling

U.S. (Lower 48) Drilling segment revenues decreased $99.4 million, or 78.7 percent, to $26.9 million for the nine months ended September 30, 2015 compared with $126.3 million for the nine months ended September 30, 2014. The decrease in revenues was primarily due to lower utilization and a decline in average dayrates for the barge drilling business due to substantial reductions in drilling activity by operators in the inland waters of the GOM resulting from lower oil prices.

U.S. (Lower 48) Drilling segment operating gross margin excluding depreciation and amortization decreased $61.0 million, or 106.5 percent, to a loss of $3.7 million for the nine months ended September 30, 2015 compared with income of $57.3 million for the nine months ended September 30, 2014. The decrease was primarily due to the decline in utilization and average dayrates discussed above.

International & Alaska Drilling

International & Alaska Drilling segment revenues decreased $4.2 million, or 1.2 percent, to $339.6 million for the nine months ended September 30, 2015 compared with $343.8 million for the nine months ended September 30, 2014. The decrease in segment revenues was driven by reduced utilization in our Latin America and Eastern Hemisphere regions primarily due to low oil prices, the completion of an O&M project in Papua New Guinea in May 2014, and a reduced dayrate for our Sakhalin Island drilling operation as the company-owned rig has been on a reduced standby rate since November 2014. In addition, we experienced

declines in revenue associated with our project services activities. The decrease in revenues was partially offset by higher reimbursable expenses and increased average dayrates driven by additional personnel for our Sakhalin Island O&M operations, as well as a two-rig O&M contract in Abu Dhabi that commenced during the 2015 first quarter. Approximately $67.2 million and $51.1 million of total segment revenues were attributable to reimbursable costs for the nine months ended September 30, 2015 and 2014, respectively, which increased revenues, but had minimal impact on operating margins.

International & Alaska Drilling operating gross margin excluding depreciation and amortization increased $18.2 million, or 26.4 percent, to $87.1 million for the nine months ended September 30, 2015 compared with $68.9 million for the nine months ended September 30, 2014. The increase in operating gross margin excluding depreciation and amortization was primarily due to the benefit of higher margins earned on our project services activities, an increase in our O&M activity described above and the benefit of lower operating costs in certain locations.

Rental Tools Services Business Line

Rental Tools segment revenues decreased $58.4 million, or 22.9 percent, to $197.0 million for the nine months ended September 30, 2015 compared with $255.4 million for the nine months ended September 30, 2014. The decrease was primarily due to reduced customer activity resulting from lower oil prices.

Rental Tools segment operating gross margin excluding depreciation and amortization decreased $29.5 million, or 30.2 percent, to $68.3 million in the nine months ended September 30, 2015 compared with $97.8 million for the nine months ended September 30, 2014. The decrease in operating gross margin excluding depreciation and amortization is primarily due to the decline in our U.S. operations discussed above, offset by an increase in margin for our international operations driven by the contribution of certain higher margin rental jobs and reductions in operating costs.

Other Financial Data

General and administrative expense

General and administration expense increased $3.9 million to $29.2 million for the nine months ended September 30, 2015 compared with $25.3 million for the nine months ended September 30, 2014. The increase is primarily driven by increased expenses as we implemented the second phase of our new enterprise resource planning system in 2015. Additionally, the nine months ended September 30, 2014 benefited from a $2.75 million reimbursement received from an escrow account related to the ITS acquisition.

Provision for reduction in carrying value of certain assets

During the nine months ended September 30, 2015, we recorded a $3.2 million provision for reduction in carrying value of certain assets. During the second quarter of 2015, we recorded $2.3 million related to certain international rental tools and drilling rigs. Management concluded that due to changing market conditions the rigs were no longer marketable and the carrying value of the rigs and equipment was no longer recoverable. During the third quarter of 2015, we recorded a $0.9 million provision for reduction in carrying value related to certain assets in our International & Alaska Drilling segment. Management concluded that due to changing market conditions the carrying value of the assets is no longer recoverable.

Gain/loss on disposition of assets

Net gains recognized on asset dispositions were $2.7 million during the nine months ended September 30, 2015 compared with $0.4 million during the nine months ended September 30, 2014. During the 2015 first quarter we received an insurance settlement related to previously realized asset losses. Activity in both periods included the result of asset sales. We periodically sell equipment deemed to be excess, obsolete, or not currently required for operations.

Interest income and expense

Interest expense increased $0.3 million to $33.8 million for the nine months ended September 30, 2015 compared with $33.5 million for the nine months ended September 30, 2014. The increase in interest expense is primarily due to a lower amount of capitalized interest and higher fees on the unused portion of the 2015 Revolver. Partially offsetting the increase is a decrease in debt related interest expense resulting from lower interest rates and a decreased amount of total outstanding debt. Interest income during the 2015 and 2014 third quarters, and interest income during the nine months ended September 30, 2015 and 2014, respectively, was nominal.

Loss on extinguishment of debt

There were no debt extinguishment costs incurred during the nine months ended September 30, 2015, compared with a loss on extinguishment of debt of $30.2 million during the nine months ended September 30, 2014, resulting from the January 2014 tender and consent solicitation with respect to the 9.125% Notes.

Other income and expense

We incurred $3.6 million of other expense for the nine months ended September 30, 2015 compared with $1.4 million of other income for the nine months ended September 30, 2014. Other expense for the nine months ended September 30, 2015 was primarily driven by losses related to foreign currency fluctuations and a loss on divestiture of our controlling interest in a consolidated joint venture. Other income for the nine months ended September 30, 2014 was primarily related to earnings from our investment in an unconsolidated subsidiary that was acquired as part of the ITS Acquisition.

Income tax expense (benefit)

During the nine months ended September 30, 2015 we had income tax expense of $24.8 million compared to income tax expense of $14.1 million for the nine months ended September 30, 2014. Despite the pre-tax loss for the nine months ended September 30, 2015, we recognized income tax expense as a result of recording a valuation allowance of $36.6 million primarily on U.S. foreign tax credits and certain foreign net operating losses. We established the valuation allowance based on the weight of available evidence, both positive and negative, including results of recent and current operations and our estimates of future taxable income or loss by jurisdiction in which we operate. 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 business considerations. 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.

LIQUIDITY AND CAPITAL RESOURCES

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

The following table provides a summary of our total liquidity:



	September 30, 2015
Dollars in thousands
Cash and cash equivalents on hand	$	104,651
Availability under 2015 Revolver ^{(1), (2)}	186,200
Total liquidity	$	290,851

(1) Availability under the 2015 Revolver included $200 million undrawn portion of our 2015 Revolver less $13.8 million of letters of credit outstanding.

(2) In order to access the 2015 Revolver, we must be in compliance with the covenants contained in the 2015 Secured Credit Agreement (as amended by the Second Amendment).

Cash Flows

The following table provides a summary of our cash flow activity:



	Nine Months Ended September 30, 2015
Dollars in thousands	2015			2014
Operating Activities	$	108,852		$	144,351
Investing Activities	(79,669		)	(148,815		)
Financing Activities	(32,988		)	(65,914		)
Net change in cash and cash equivalents	$	(3,805	)	$	(70,378	)

Operating Activities

As of September 30, 2015, we had cash and cash equivalents of $104.7 million, a decrease of $3.8 million from December 31, 2014. Cash flows from operating activities for the nine months ended September 30, 2015 were an inflow of $108.9 million, compared with an inflow of $144.4 million for the 2014 comparable period. Changes in working capital were a source of cash of $29.6 million for the nine months ended September 30, 2015 compared to a use of cash of $18.6 million for the nine months ended September 30, 2014. Over the past few years we have reinvested a substantial portion of our operating cash flows to enhance our fleet of drilling rigs and our rental tools equipment inventory. It is our long term intention to utilize our operating cash flows to fund maintenance and growth of our rental tool assets and drilling rigs; however, given the decline in demand in the current oil and natural gas services market, our short-term focus is to preserve liquidity by managing our costs. Operating cash flows for the nine months ended September 30, 2014 were also impacted by payments of debt extinguishment costs, as well as increased receivables, inventory, and accounts payable related to the ITS Acquisition. Changes in cash from operating activities for both periods were also impacted by non-cash charges such as depreciation expense, deferred tax benefit, and stock compensation expense.

Investing Activities

Cash flows used in investing activities were $79.7 million for the nine months ended September 30, 2015 compared with $148.8 million for the 2014 comparable period. Our primary use of cash during the nine months ended September 30, 2015 and 2014 was $72.5 million and $151.1 million, respectively, for capital expenditures. Capital expenditures in each period were primarily for tubular and other products for our Rental Tools Services business and rig-related enhancements and maintenance. In addition, during the nine months ended September 30, 2015 we had a use of cash of $10.4 million, net of cash acquired, for the 2M-Tek Acquisition. During the nine months ended September 30, 2014, we had a use of cash of $12.3 million related to the

acquisition of a 1500 horsepower posted barge rig for our Gulf of Mexico drilling fleet.

Financing Activities

Cash flows used in financing activities were $33.0 million for the nine months ended September 30, 2015, primarily driven by the repayment of the $30.0 million term loan in the first quarter of 2015. Cash flows used in financing activities were $65.9 million for the 2014 comparable period, primarily related to the repayment of $425.0 million of our 9.125% Notes, payments of related tender and consent premiums of $26.2 million, $7.5 million related to the repayment of the term loan, and payment of debt issuance costs of $7.6 million. Cash provided by financing activities for the nine months ended September 30, 2014 included proceeds of $360.0 million from issuance of our 6.75% Notes and reborrowing of a $40.0 million Term Loan under our 2012 Secured Credit Agreement.

Long-Term Debt Summary

Our principal amount of long-term debt, including current portion, was $585.0 million as of September 30, 2015 which consisted of:

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

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

6.75% Senior Notes, due July 2022

7.50% Senior Notes, due August 2020

9.125% Senior Notes, due April 2018

On March 22, 2010, we issued $300.0 million aggregate principal amount of the 9.125% Notes and on April 25, 2012, we issued an additional $125.0 million aggregate principal amount of 9.125% Notes.

2015 Secured Credit Agreement

Credit Agreement up to an additional $75 million. We incurred debt issuance costs related to the 2015 Secured Credit Agreement of approximately $2.0 million and had approximately $0.8 million of remaining debt issuance costs for the 2012 Secured Credit agreement. The total debt issuance costs of $2.8 million ($2.6 million, net of amortization as of September 30, 2015) are being amortized over the term of the 2015 Secured Credit Agreement on a straight line basis.

2012 Secured Credit Agreement

2012 Revolver

Term Loan

Off-Balance Sheet Arrangements

We do not have any unconsolidated special-purpose entities, off-balance sheet financing arrangements or guarantees of third-party financial obligations. We have no energy or commodity contracts.

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 2014 Annual Report on Form 10-K filed with the SEC on February 25, 2015. For more information on market risk, see Part II, Item 7A in our 2014 Annual Report on Form 10-K.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

In accordance with Rules 13a-15 and 15d-15 under the Exchange Act, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective, as of September 30, 2015 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 Securities and Exchange Commission's rules and forms and accumulated and communicated to our management, including our Chief Executive Officer and our Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

Changes in Internal Controls Over Financial Reporting

There have been no changes in our internal controls over financial reporting during the quarter ended September 30, 2015 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

For information regarding legal proceedings, see Note 12, “Commitments and Contingencies,” in Item 1 of Part I of this quarterly report on Form 10-Q, which information is incorporated into this item by reference.

Item 1A. Risk Factors

There have been no material changes from the risk factors disclosed in Item 1A. Risk Factors of our Annual Report on Form 10-K for the year ended December 31, 2014.

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.

Item 6. Exhibits

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



Exhibit Number		Description

3.1	—	Restated Certificate of Incorporation of Parker Drilling Company, as amended on May 16, 2007 (incorporated by reference to Exhibit 3.1 to the Company’s Quarterly Report on Form 10-Q filed on November 9, 2007).

3.2	—	By-laws of Parker Drilling Company, as amended and restated as of July 31, 2014 (incorporated by reference to Exhibit 3.1 to the Company's Current Report on Form 8-K filed on August 1, 2014).

10.1	—	Second Amendment to Second Amended and Restated Credit Agreement, dated September 29, 2015, among Parker Drilling Company as Borrower, Bank of America, N.A., as Administrative Agent and L/C Issuer, Wells Fargo Bank, National Association, as Syndication Agent, Barclays Bank PLC, as Documentation Agent, and the other lenders and L/C issuers from time to time party thereto.

12.1	—	Computation of Ratio of Earnings to Fixed Charges.

31.1	—	Gary G. Rich, Chairman, President and Chief Executive Officer, Rule 13a-14(a)/15d-14(a) Certification.

31.2	—	Christopher T. Weber, Senior Vice President and Chief Financial Officer, Rule 13a-14(a)/15d-14(a) Certification.

32.1	—	Gary G. Rich, Chairman, President and Chief Executive Officer, Section 1350 Certification.

32.2	—	Christopher T. Weber, Senior Vice President and Chief Financial Officer, Section 1350 Certification.

101.INS	—	XBRL Instance Document.

101.SCH	—	XBRL Taxonomy Schema Document.

101.CAL	—	XBRL Calculation Linkbase Document.

101.LAB	—	XBRL Label Linkbase Document.

101.PRE	—	XBRL Presentation Linkbase Document.

101.DEF	—	XBRL Definition Linkbase Document.

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:	November 4, 2015	By:	/s/ Gary G. Rich
			Gary G. Rich Chairman, President and Chief Executive Officer

		By:	/s/ Christopher T. Weber
			Christopher T. Weber Senior Vice President and Chief Financial Officer

INDEX TO EXHIBITS



Exhibit Number		Description

3.1	—	Restated Certificate of Incorporation of Parker Drilling Company, as amended on May 16, 2007 (incorporated by reference to Exhibit 3.1 to the Company’s Quarterly Report on Form 10-Q filed on November 9, 2007).

3.2	—	By-laws of Parker Drilling Company, as amended and restated as of July 31, 2014 (incorporated by reference to Exhibit 3.1 to the Company's Current Report on Form 8-K filed on August 1, 2014).

10.1	—	Second Amendment to Second Amended and Restated Credit Agreement, dated September 29, 2015, among Parker Drilling Company as Borrower, Bank of America, N.A., as Administrative Agent and L/C Issuer, Wells Fargo Bank, National Association, as Syndication Agent, Barclays Bank PLC, as Documentation Agent, and the other lenders and L/C issuers from time to time party thereto.

12.1	—	Computation of Ratio of Earnings to Fixed Charges.

31.1	—	Gary G. Rich, Chairman, President and Chief Executive Officer, Rule 13a-14(a)/15d-14(a) Certification.

31.2	—	Christopher T. Weber, Senior Vice President and Chief Financial Officer, Rule 13a-14(a)/15d-14(a) Certification.

32.1	—	Gary G. Rich, Chairman, President and Chief Executive Officer, Section 1350 Certification.

32.2	—	Christopher T. Weber, Senior Vice President and Chief Financial Officer, Section 1350 Certification.

101.INS	—	XBRL Instance Document.

101.SCH	—	XBRL Taxonomy Schema Document.

101.CAL	—	XBRL Calculation Linkbase Document.

101.LAB	—	XBRL Label Linkbase Document.

101.PRE	—	XBRL Presentation Linkbase Document.

101.DEF	—	XBRL Definition Linkbase Document.