UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
 
(Mark One)
x
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934
For The Quarterly Period Ended June 30, 2016
OR
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                      to                         
Commission File Number 1-7573 
PARKER DRILLING COMPANY
(Exact name of registrant as specified in its charter)
Delaware
 
73-0618660
(State or other jurisdiction of
incorporation or organization)
 
(I.R.S. Employer
Identification No.)
 
 
 
5 Greenway Plaza, Suite 100,
Houston, Texas
 
77046
(Address of principal executive offices)
 
(Zip code)
(281) 406-2000
(Registrant’s telephone number, including area code) 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No  ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files.    Yes  x    No  ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer
 
¨
  
Accelerated filer
 
x
 
 
 
 
Non-accelerated filer
 
¨ (Do not check if a smaller reporting company)
  
Smaller reporting company
 
¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ¨    No  x
As of August 1, 2016 there were 124,695,455 common shares outstanding.    



TABLE OF CONTENTS
 
 
Page
 
 
 
 


2


PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
PARKER DRILLING COMPANY AND SUBSIDIARIES
CONSOLIDATED CONDENSED BALANCE SHEETS
(Dollars in Thousands) 
 
June 30,
2016
 
December 31,
2015
 
(Unaudited)
 
 
ASSETS
Current assets:
 
 
 
Cash and cash equivalents
$
109,034

 
$
134,294

Accounts and Notes Receivable, net of allowance for bad debts of $8,192 at June 30, 2016 and $8,694 at December 31, 2015.
153,189

 
175,105

Rig materials and supplies
32,615

 
34,937

Other current assets
26,805

 
22,405

Total current assets
321,643

 
366,741

Property, plant and equipment, net of accumulated depreciation of $1,360,282 at June 30, 2016 and $1,302,380 at December 31, 2015.
747,017

 
805,841

Goodwill (Note 3)
6,708

 
6,708

Intangible assets, net (Note 3)
11,392

 
13,377

Deferred income taxes
87,311

 
139,282

Other noncurrent assets
38,700

 
34,753

Total assets
$
1,212,771

 
$
1,366,702

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
 
 
 
Accounts payable and accrued liabilities
109,091

 
129,703

Accrued income taxes
5,777

 
6,418

Total current liabilities
114,868

 
136,121

Long-term debt, net of unamortized debt issuance costs of $9,452 at June 30, 2016 and $10,202 at December 31, 2015.
575,548

 
574,798

Other long-term liabilities
15,049

 
18,617

Long-term deferred tax liability
76,475

 
68,654

Commitments and contingencies (Note 11)
 
 
 
Stockholders’ equity:
 
 
 
Common stock
20,766

 
20,518

Capital in excess of par value
670,419

 
669,120

Accumulated deficit
(254,895
)
 
(119,238
)
Accumulated other comprehensive loss
(5,459
)
 
(1,888
)
Total stockholders’ equity
430,831

 
568,512

Total liabilities and stockholders’ equity
$
1,212,771

 
$
1,366,702

See accompanying notes to the unaudited consolidated condensed financial statements.

3


PARKER DRILLING COMPANY AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF OPERATIONS
(Dollars in Thousands, Except Per Share Data)
(Unaudited)
 
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2016
 
2015
 
2016
 
2015
Revenues
$
105,287

 
$
185,941

 
$
235,790

 
$
390,017

Expenses:
 
 
 
 
 
 
 
Operating expenses
89,195

 
143,569

 
197,312

 
282,839

Depreciation and amortization
36,317

 
38,351

 
72,131

 
78,890

 
125,512

 
181,920

 
269,443

 
361,729

Total operating gross margin
(20,225
)
 
4,021

 
(33,653
)
 
28,288

General and administration expense
(7,995
)
 
(9,511
)
 
(17,776
)
 
(20,348
)
Provision for reduction in carrying value of certain assets
—

 
(2,316
)
 
—

 
(2,316
)
Gain (loss) on disposition of assets, net
(2
)
 
(138
)
 
(62
)
 
2,303

Total operating income (loss)
(28,222
)
 
(7,944
)
 
(51,491
)
 
7,927

Other income and (expense):
 
 
 
 
 
 
 
Interest expense
(12,187
)
 
(11,396
)
 
(23,749
)
 
(22,474
)
Interest income
32

 
19

 
39

 
202

Other
(358
)
 
(1,529
)
 
2,127

 
(2,909
)
Total other expense
(12,513
)
 
(12,906
)
 
(21,583
)
 
(25,181
)
Loss before income taxes
(40,735
)
 
(20,850
)
 
(73,074
)
 
(17,254
)
Income tax expense (benefit)
(913
)
 
(6,916
)
 
62,583

 
(7,098
)
Net loss
(39,822
)
 
(13,934
)
 
(135,657
)
 
(10,156
)
Less: Net income attributable to noncontrolling interest
—

 
95

 
—

 
651

Net loss attributable to controlling interest
$
(39,822
)
 
$
(14,029
)
 
$
(135,657
)
 
$
(10,807
)
Basic loss per share
$
(0.32
)
 
$
(0.11
)
 
$
(1.10
)
 
$
(0.09
)
Diluted loss per share
$
(0.32
)
 
$
(0.11
)
 
$
(1.10
)
 
$
(0.09
)
 
 
 
 
 
 
 
 
Number of common shares used in computing earnings per share:
 
 
 
 
 
 
 
Basic
124,101,349

 
122,481,425

 
123,595,793

 
122,175,511

Diluted
124,101,349

 
122,481,425

 
123,595,793

 
122,175,511


See accompanying notes to the unaudited consolidated condensed financial statements.


4


PARKER DRILLING COMPANY AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Dollars in Thousands)
(Unaudited)
 
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2016
 
2015
 
2016
 
2015
Comprehensive income:
 
 
 
 
 
 
 
Net loss
$
(39,822
)
 
$
(13,934
)
 
$
(135,657
)
 
$
(10,156
)
Other comprehensive income (loss), net of tax:
 
 
 
 
 
 
 
Currency translation difference on related borrowings
(307
)
 
647

 
195

 
(1,023
)
Currency translation difference on foreign currency net investments
(2,228
)
 
1,723

 
(3,766
)
 
874

Total other comprehensive income (loss), net of tax:
(2,535
)
 
2,370

 
(3,571
)
 
(149
)
Comprehensive loss
(42,357
)
 
(11,564
)
 
(139,228
)
 
(10,305
)
Comprehensive loss attributable to noncontrolling interest
—

 
(95
)
 
—

 
(489
)
Comprehensive loss attributable to controlling interest
$
(42,357
)
 
$
(11,659
)
 
$
(139,228
)
 
$
(10,794
)

See accompanying notes to the unaudited consolidated condensed financial statements.


5


PARKER DRILLING COMPANY AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
(Unaudited)

 
Six Months Ended June 30,
 
2016
 
2015
Cash flows from operating activities:
 
 
 
Net loss
$
(135,657
)
 
$
(10,156
)
Adjustments to reconcile net income to net cash flows from operating activities:
 
 
 
Depreciation and amortization
72,131

 
78,890

Accretion of contingent consideration
419

 
306

Loss on debt modification
1,088

 
—

Provision for reduction in carrying value of certain assets
—

 
2,316

(Gain) loss on disposition of assets
62

 
(2,303
)
Deferred income tax expense (benefit)
59,305

 
(17,126
)
Expenses not requiring cash
(5,226
)
 
5,308

Change in assets and liabilities:
 
 
 
Accounts and notes receivable
22,319

 
39,683

Other assets
(2,992
)
 
(7,352
)
Accounts payable and accrued liabilities
(6,862
)
 
14,763

Accrued income taxes
(3,985
)
 
(1,236
)
Net cash provided by operating activities
602

 
103,093

 
 
 
 
Cash flows from investing activities:
 
 
 
Capital expenditures
(16,257
)
 
(54,605
)
Proceeds from the sale of assets
1,387

 
288

Proceeds from insurance settlements
—

 
2,500

Acquisition, net of cash acquired
—

 
(10,431
)
Net cash used in investing activities
(14,870
)
 
(62,248
)
 
 
 
 
Cash flows from financing activities:
 
 
 
Repayments of long-term debt
—

 
(30,000
)
Payments of debt issuance costs
—

 
(1,359
)
Payment for noncontrolling interest
(3,375
)
 
—

Payments of contingent consideration
(6,000
)
 
—

Excess tax (expense) from stock based compensation
(1,617
)
 
(999
)
Net cash used in financing activities
(10,992
)
 
(32,358
)
 
 
 
 
Net increase (decrease) in cash and cash equivalents
(25,260
)
 
8,487

Cash and cash equivalents, beginning of year
134,294

 
108,456

Cash and cash equivalents, end of period
$
109,034

 
$
116,943

 
 
 
 
Supplemental cash flow information:
 
 
 
Interest paid
$
20,588

 
$
20,805

Income taxes paid
$
9,672

 
$
16,436


See accompanying notes to the unaudited consolidated condensed financial statements.


6


PARKER DRILLING COMPANY AND SUBSIDIARIES
NOTES TO THE UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
Note 1 - General
The Consolidated Condensed Financial Statements as of June 30, 2016 and for the three and six months ended June 30, 2016 and 2015 are unaudited. In the opinion of Parker Drilling Company (Parker Drilling or the Company), these financial statements include all adjustments, which, unless otherwise disclosed, are of a normal recurring nature, necessary for a fair presentation of the financial position, results of operations, comprehensive income, and cash flows for the periods presented. The results for interim periods are not necessarily indicative of results for the entire year. The financial statements presented herein should be read in connection with the financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2015.
Nature of Operations — Our business is comprised of two business lines: (1) Drilling Services and (2) Rental Tools Services. We report our Rental Tools Services business as one reportable segment (Rental Tools) and report our Drilling Services business as two reportable segments: (1) U.S. (Lower 48) Drilling and (2) International & Alaska Drilling.
In our Drilling Services business, we drill oil and gas wells for customers in both the United States (U.S.) and international markets. We provide this service with both Company-owned rigs and customer-owned rigs. We refer to the provision of drilling services with customer-owned rigs as our operations and maintenance (O&M) service in which operators own their own drilling rigs but choose Parker Drilling to operate and maintain the rigs for them. The nature and scope of activities involved in drilling an oil and gas well are similar whether the well is drilled with a Company-owned rig (as part of a traditional drilling contract) or a customer-owned rig (as part of an O&M contract). In addition, we provide project related services, such as engineering, procurement, project management and commissioning of customer owned drilling facility projects. We have extensive experience and expertise in drilling geologically difficult wells and in managing the logistical and technological challenges of operating in remote, harsh and ecologically sensitive areas.
    Our U.S. (Lower 48) Drilling segment provides drilling services with our Gulf of Mexico (GOM) barge drilling fleet and markets U.S. (Lower 48) based O&M services. Our GOM barge drilling fleet operates barge rigs that drill for oil and natural gas in shallow waters in and along the inland waterways and coasts of Louisiana, Alabama and Texas. The majority of these wells are drilled in shallow water depths ranging from 6 to 12 feet. Our International & Alaska Drilling segment provides drilling services, with Company-owned rigs as well as through O&M contracts, and project related services. We strive to deploy our fleet of Company-owned rigs in markets where we expect to have opportunities to keep the rigs consistently utilized and build a sufficient presence to achieve efficient operating scale.    
In our Rental Tools Services business, we provide premium rental equipment and services to exploration and production (E&P) companies, drilling contractors and service companies on land and offshore in the U.S. and select international markets. Tools we provide include standard and heavy-weight drill pipe, all of which are available with standard or high-torque connections, tubing, pressure control equipment, including blow-out preventers (BOPs), drill collars and more. We also provide well construction services, which include tubular running services and downhole tools, and well intervention services, which include whipstock, fishing products and related services, as well as inspection and machine shop support. Rental tools are used during well drilling programs and are requested by the customer when they are needed, requiring us to keep a broad inventory of rental tools in stock. Rental tools are usually rented on a daily or monthly basis.
Consolidation — The consolidated condensed financial statements include the accounts of the Company and subsidiaries over which we exercise control or in which we have a controlling financial interest, including entities, if any, in which the Company is allocated a majority of the entity’s losses or returns, regardless of ownership percentage. If a subsidiary of Parker Drilling has a 50 percent interest in an entity but Parker Drilling’s interest in the subsidiary or the entity does not meet the consolidation criteria, then that interest is accounted for under the equity method.
Noncontrolling Interest — We apply accounting standards related to noncontrolling interests for ownership interests in our subsidiaries held by parties other than Parker Drilling. We report noncontrolling interest as equity on the consolidated balance sheets and report net income (loss) attributable to controlling interest and to noncontrolling interest separately on the consolidated condensed statements of operations. During the fourth quarter of 2015, we purchased the remaining noncontrolling interest of ITS Arabia Limited for $6.75 million, of which $3.4 million was paid in the 2015 fourth quarter. The final payment of the purchase price was made during the second quarter of 2016. At the time of purchase, the carrying value of the noncontrolling interest was $3.0 million.
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.

7


Revenue Recognition — Drilling revenues and expenses, comprised of daywork drilling contracts, call-outs against master service agreements and engineering and related project services contracts, are recognized as services are performed and collection is reasonably assured. For certain contracts, we receive payments contractually designated for the mobilization of rigs and other drilling equipment. Mobilization payments received, and direct costs incurred for the mobilization, are deferred and recognized over the primary term of the related drilling contract; however, costs incurred to relocate rigs and other drilling equipment to areas in which a contract has not been secured are expensed as incurred. For contracts that are terminated prior to the specified term, early termination payments received by us are recognized as revenues when all contractual requirements are met. Revenues from rental activities are recognized ratably over the rental term, which is generally less than six months. Our project related services contracts include engineering, consulting, and project management scopes of work and revenue is typically recognized on a time and materials basis.
Reimbursable Revenues — The Company recognizes reimbursements received for out-of-pocket expenses incurred as revenues and accounts for out-of-pocket expenses as direct operating costs. Such amounts totaled $18.9 million and $27.8 million for the three months ended June 30, 2016 and 2015, respectively, and $37.9 million and $47.5 million for the six months ended June 30, 2016 and 2015, respectively. Additionally, the Company typically receives a nominal handling fee, which is recognized as revenues in our consolidated statement of operations.
Use of Estimates — The preparation of consolidated condensed financial statements in accordance with accounting policies generally accepted in the United States (U.S. GAAP) requires management to make estimates and assumptions that affect our reported amounts of assets and liabilities, our disclosure of contingent assets and liabilities at the date of the consolidated condensed financial statements, and our revenues and expenses during the periods reported. Estimates are typically used when accounting for certain significant items such as legal or contractual liability accruals, mobilization and deferred mobilization, self-insured medical/dental plans, income taxes and valuation allowance, and other items requiring the use of estimates. Estimates are based on a number of variables which may include third party valuations, historical experience, where applicable, and assumptions that we believe are reasonable under the circumstances. Due to the inherent uncertainty involved with estimates, actual results may differ from management estimates.
Purchase Price Allocation — We allocate the purchase price of an acquired business to its identifiable assets and liabilities in accordance with the acquisition method based on estimated fair values at the transaction date. Transaction and integration costs associated with an acquisition are expensed as incurred. The excess of the purchase price over the amount allocated to the assets and liabilities, if any, is recorded as goodwill. We use all available information to estimate fair values, including quoted market prices, the carrying value of acquired assets, and widely accepted valuation techniques such as discounted cash flows. We typically engage third-party appraisal firms to assist in fair value determination of inventories, identifiable intangible assets, and any other significant assets or liabilities. Judgments made in determining the estimated fair value assigned to each class of assets acquired and liabilities assumed, as well as asset lives, can materially impact our results of operations. See Note 2 - Acquisitions for further discussion.
Goodwill — We account for all business combinations using the acquisition method of accounting. Under this method, assets and liabilities, including any remaining noncontrolling interests, are recognized at fair value at the date of acquisition. The excess of the purchase price over the fair value of assets acquired, net of liabilities assumed, plus the value of any noncontrolling interests, is recognized as goodwill. We perform our annual goodwill impairment review as of October 1 of each year, and more frequently if negative conditions or other triggering events arise. The quantitative impairment test we perform for goodwill utilizes certain assumptions, including forecasted revenue and costs assumptions. See Note 3 - Goodwill and Intangible Assets for further discussion.    
Intangible Assets — Our intangible assets are related to trade names, customer relationships, and developed technology, which were acquired through acquisition and are generally amortized over a weighted average period of approximately three to six years. We assess the recoverability of the unamortized balance of our intangible assets when indicators of impairment are present based on expected future profitability and undiscounted expected cash flows and their contribution to our overall operations. Should the review indicate that the carrying value is not fully recoverable, the excess of the carrying value over the fair value of the intangible assets would be recognized as an impairment loss. See Note 3 - Goodwill and Intangible Assets for further discussion.
Impairment — We evaluate the carrying amounts of long-lived assets for potential impairment when events occur or circumstances change that indicate the carrying values of such assets may not be recoverable. We evaluate recoverability by determining the undiscounted estimated future net cash flows for the respective asset groups identified. If the sum of the estimated undiscounted cash flows is less than the carrying value of the asset group, we measure the impairment as the amount by which the assets’ carrying value exceeds the fair value of such assets. Management considers a number of factors such as estimated future cash flows from the assets, appraisals and current market value analysis in determining fair value. Assets are written down to fair value if the final estimate of current fair value is below the net carrying value. The assumptions used in the impairment evaluation are inherently uncertain and require management judgment.

8


    
Concentrations of Credit Risk — Financial instruments that potentially subject the Company to concentrations of credit risk consist primarily of trade receivables with a variety of national and international oil and natural gas companies. We generally do not require collateral on our trade receivables. We depend on a limited number of significant customers. Our largest customer, Exxon Neftegas Limited (ENL), constituted approximately 39.8 percent of our consolidated revenues for the six months ended June 30, 2016. Excluding reimbursable revenues of $36.9 million, ENL constituted approximately 28.7 percent of our total consolidated revenues for the six months ended June 30, 2016. Our second largest customer, BP Exploration Alaska, Inc. (BP), constituted approximately 11.9 percent of our consolidated revenues for the six months ended June 30, 2016.
At June 30, 2016 and December 31, 2015, we had deposits in domestic banks in excess of federally insured limits of approximately $69.1 million and $91.3 million, respectively. In addition, we had uninsured deposits in foreign banks as of June 30, 2016 and December 31, 2015 of $41.7 million and $44.1 million, respectively.    
Income Taxes — Income taxes are accounted for under the asset and liability method and have been provided for based upon tax laws and rates in effect in the countries in which operations are conducted and income or losses are generated. There is little or no expected relationship between the provision for or benefit from income taxes and income or loss before income taxes as the countries in which we operate have taxation regimes that vary not only with respect to nominal rate, but also in terms of the availability of deductions, credits, and other benefits. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the year in which the temporary differences are expected to be recovered or settled and the effect of changes in tax rates is recognized in income in the period in which the change is enacted. Valuation allowances are established to reduce deferred tax assets when it is more likely than not that some portion or all of the deferred tax assets will not be realized. In order to determine the amount of deferred tax assets or liabilities, as well as the valuation allowances, we must make estimates and assumptions regarding future taxable income, where rigs will be deployed and other matters. Changes in these estimates and assumptions, including changes in tax laws and other changes impacting our ability to recognize the underlying deferred tax assets, could require us to adjust the valuation allowances.
The Company recognizes the effect of income tax positions only if those positions are more likely than not to be sustained. Recognized income tax positions are measured at the largest amount that is greater than 50 percent likely of being realized and changes in recognition or measurement are reflected in the period in which the change in judgment occurs.
Legal and Investigation Matters — We accrue estimates of the probable and estimable costs for the resolution of certain legal and investigation matters. We do not accrue any amounts for other matters for which the liability is not probable and reasonably estimable.  Generally, the estimate of probable costs related to these matters is developed in consultation with our legal advisors. The estimates take into consideration factors such as the complexity of the issues, litigation risks and settlement costs. If the actual settlement costs, final judgments, or fines, after appeals, differ from our estimates, our future financial results may be adversely affected.
Note 2 - Acquisitions     
Acquisition of 2M-Tek
On April 17, 2015 we acquired 2M-Tek, a Louisiana-based manufacturer of equipment for tubular running and related well services (the 2M-Tek Acquisition) for an initial purchase price of $10.4 million paid at the closing of the acquisition, plus $8.0 million of contingent consideration payable to the seller upon the achievement of certain milestones over the 24-month period following the closing of the 2M-Tek Acquisition. The fair value of the consideration transferred was $17.2 million, which includes the $10.4 million liability paid at closing plus the estimated fair value of the contingent consideration of $6.8 million. We paid $2.0 million of the contingent consideration upon the achievement of certain milestones during the fourth quarter of 2015 and $2.0 million during the first quarter of 2016. The remaining $4.0 million of the contingent consideration was paid in April 2016.
Note 3 - Goodwill and Intangible Assets    
As part of the 2M-Tek Acquisition we recognized $6.7 million of goodwill and acquired definite-lived intangible assets with an acquisition date fair value of $13.5 million. As part of the 2013 acquisition of International Tubular Services Limited (ITS) and related assets (the ITS Acquisition), we acquired definite-lived intangible assets with an acquisition date fair value of $8.5 million. All of the Company’s goodwill and intangible assets are allocated to the Rental Tools segment.

9


Goodwill
During the 2016 second quarter, circumstances indicated that the fair value of the reporting unit may not be in excess of the carrying value of the goodwill. Therefore we performed a goodwill impairment review and determined that the fair value of the reporting unit exceeded its carrying value and therefore, no goodwill impairment was identified. Should current market conditions worsen or persist for an extended period of time, an impairment of the carrying value of our goodwill could occur.
The change in the carrying amount of goodwill for the period ended June 30, 2016 is as follows:
Dollars in thousands
Goodwill
Balance at December 31, 2015
$
6,708

Additions
—

Balance at June 30, 2016
$
6,708

Of the total amount of goodwill recognized, zero is expected to be deductible for income tax purposes.
Intangible Assets
Intangible Assets consist of the following:
 
 
Balance at June 30, 2016
Dollars in thousands
Estimated Useful Life (Years)
Gross Carrying Amount
 
Write-off Due to Sale in 2015 (1)
 
Accumulated Amortization
 
Net Carrying Amount
Amortized intangible assets:
 
 
 
 
 
 
 
 
Developed Technology
6
$
11,630

 
—

 
$
(2,423
)
 
$
9,207

Customer Relationships
3
5,400

 
(264
)
 
(5,136
)
 
—

Trade Names
5
4,940

 
(332
)
 
(2,423
)
 
2,185

Total Amortized intangible assets
 
$
21,970

 
$
(596
)
 
$
(9,982
)
 
$
11,392

(1) During the 2015 fourth quarter, we sold our controlling interest in a joint venture in Egypt resulting in the write-off of $0.6 million of intangible assets related to customer relationships and trade name acquired as part of the ITS Acquisition.
Amortization expense was $2.0 million and $1.8 million for the six months ended June 30, 2016 and 2015, respectively.
Our remaining intangibles amortization expense for the next five years is presented below:
Dollars in thousands
Expected future intangible amortization expense
2016
$
1,463

2017
$
2,801

2018
$
2,306

2019
$
2,306

2020
$
2,030

Beyond 2020
$
486


10


Note 4 - Earnings (Loss) Per Share (EPS)  
 
Three Months Ended June 30, 2016
 
Income/(Loss)
(Numerator)
 
Shares
(Denominator)
 
Per-Share
Amount
Basic EPS
$
(39,822,000
)
 
124,101,349

 
$
(0.32
)
Effect of dilutive securities:
 
 
 
 
 
Restricted stock units
—

 
—

 
—

Diluted EPS
$
(39,822,000
)
 
124,101,349

 
$
(0.32
)
 
 
 
 
 
 
 
Six Months Ended June 30, 2016
 
Income/(Loss)
(Numerator)
 
Shares
(Denominator)
 
Per-Share
Amount
Basic EPS
$
(135,657,000
)
 
123,595,793

 
$
(1.10
)
Effect of dilutive securities:
 
 
 
 
 
Restricted stock units
—

 
—

 
—

Diluted EPS
$
(135,657,000
)
 
123,595,793

 
$
(1.10
)
 
 
 
 
 
 
 
Three Months Ended June 30, 2015
 
Income/(Loss)
(Numerator)
 
Shares
(Denominator)
 
Per-Share
Amount
Basic EPS
$
(14,029,000
)
 
122,481,425

 
$
(0.11
)
Effect of dilutive securities:
 
 
 
 
 
Restricted stock units
—

 
—

 
—

Diluted EPS
$
(14,029,000
)
 
122,481,425

 
$
(0.11
)
 
 
 
 
 
 
 
Six Months Ended June 30, 2015
 
Income/(Loss)
(Numerator)
 
Shares
(Denominator)
 
Per-Share
Amount
Basic EPS
$
(10,807,000
)
 
122,175,511

 
$
(0.09
)
Effect of dilutive securities:
 
 
 
 
 
Restricted stock units
—

 
—

 
—

Diluted EPS
$
(10,807,000
)
 
122,175,511

 
$
(0.09
)
 
 
 
 
 
 
For the three and six months ended June 30, 2016 and 2015, respectively, all common shares potentially issuable in connection with outstanding restricted stock unit awards have been excluded from the calculation of diluted EPS as the company incurred losses during the three and six month periods, therefore, inclusion of such potential common shares in the calculation would be anti-dilutive.

11


Note 5 - Accumulated Other Comprehensive Loss
Accumulated other comprehensive loss consisted of the following:
Dollars in thousands
Foreign Currency Items
December 31, 2015
$
(1,888
)
Current period other comprehensive loss
(3,571
)
June 30, 2016
$
(5,459
)
There were no amounts reclassified out of accumulated other comprehensive loss for the three months ended June 30, 2016. Amounts reclassified out of accumulated other comprehensive loss were $1.9 million for the six months ended June 30, 2016 and represent realized foreign currency translation gains.
Note 6 - Reportable Segments
Our business is comprised of two business lines: (1) Drilling Services and (2) Rental Tools Services. We report our Rental Tools Services business as one reportable segment (Rental Tools) and report our Drilling Services business as two reportable segments: (1) U.S. (Lower 48) Drilling and (2) International & Alaska Drilling. Within the three reportable segments, we have aggregated our U.S. and international rental tools business units under Rental Tools, one business unit under U.S. (Lower 48) Drilling, and our Arctic, Eastern Hemisphere and Latin America business units under International & Alaska Drilling for a total of six business units. The Company has aggregated each of its business units in one of the three reporting segments based on the guidelines of ASC Topic 280, “Segment Reporting” (ASC Topic 280). We eliminate inter-segment revenues and expenses. We disclose revenues under the three reportable segments based on the similarity of the use and markets for the groups of products and services within each segment.
Drilling Services Business Line
In our Drilling Services business, we drill oil and gas wells for customers in both the U.S. and international markets. We provide this service with both Company-owned rigs and customer-owned rigs. We refer to the provision of drilling services with customer-owned rigs as our O&M service in which operators own their own drilling rigs but choose Parker Drilling to operate and maintain the rigs for them. The nature and scope of activities involved in drilling an oil and gas well is similar whether it is drilled with a Company-owned rig (as part of a traditional drilling contract) or a customer-owned rig (as part of an O&M contract). In addition, we provide project related services, such as engineering, procurement, project management and commissioning of customer-owned drilling facility projects. We have extensive experience and expertise in drilling geologically difficult wells and in managing the logistical and technological challenges of operating in remote, harsh and ecologically sensitive areas.
U.S. (Lower 48) Drilling
Our U.S. (Lower 48) Drilling segment provides drilling services with our GOM barge drilling rig fleet and markets U.S. (Lower 48) based O&M services. Our GOM barge drilling fleet operates barge rigs that drill for oil and natural gas in shallow waters in and along the inland waterways and coasts of Louisiana, Alabama and Texas. The majority of these wells are drilled in shallow water depths ranging from 6 to 12 feet. Our rigs are suitable for a variety of drilling programs, from inland coastal waters requiring shallow draft barges, to open water drilling on both state and federal water projects requiring more robust capabilities. The barge drilling industry in the GOM is characterized by cyclical activity where utilization and dayrates are typically driven by oil and gas prices and our customers’ access to project financing. Contract terms tend to be well-to-well or multi-well programs, most commonly ranging from 45 to 150 days.
International & Alaska Drilling
Our International & Alaska Drilling segment provides drilling services, with Company-owned rigs as well as through O&M contracts, and project related services. The drilling markets in which this segment operates have one or more of the following characteristics:
•
customers that typically are major, independent or national oil and natural gas companies or integrated service providers;
•
drilling programs in remote locations with little infrastructure, requiring a large inventory of spare parts and other ancillary equipment and self-supported service capabilities;
•
complex wells and/or harsh environments (such as high pressures, deep depths, hazardous or geologically challenging conditions and sensitive environments) requiring specialized equipment and considerable experience to drill; and

12


•
drilling and O&M contracts that generally cover periods of one year or more.
Our Rental Tools Services Business
Our Rental Tools segment provides premium rental equipment and services to E&P companies, drilling contractors and service companies on land and offshore in the U.S. and select international markets. Tools we provide include standard and heavy-weight drill pipe, tubing, pressure control equipment, including BOPs, drill collars and more. We also provide well construction services, which include tubular running services and downhole tools, and well intervention services, which include whipstock, fishing products and related services, as well as inspection and machine shop support. Our largest single market for rental tools is U.S. land drilling. Rental tools are used during well drilling programs and are usually rented on a daily or monthly basis.
The following table represents the results of operations by reportable segment:
 
Three Months Ended June 30,
 
Six Months Ended June 30,
Dollars in thousands
2016
 
2015
 
2016
 
2015
Revenues: (1)
 
 
 
 
 
 
 
Drilling Services:
 
 
 
 
 
 
 
U.S. (Lower 48) Drilling
$
1,065

 
$
6,848

 
$
3,150

 
$
20,945

International & Alaska Drilling
71,926

 
114,969

 
160,545

 
228,890

Total Drilling Services
72,991

 
121,817

 
163,695

 
249,835

Rental Tools
32,296

 
64,124

 
72,095

 
140,182

Total revenues
105,287

 
185,941

 
235,790

 
390,017

Operating gross margin: (2)
 
 
 
 
 
 
 
Drilling Services:
 
 
 
 
 
 
 
U.S. (Lower 48) Drilling
(9,011
)
 
(7,552
)
 
(17,571
)
 
(13,274
)
International & Alaska Drilling
3,196

 
6,844

 
8,274

 
24,208

Total Drilling Services
(5,815
)
 
(708
)
 
(9,297
)
 
10,934

Rental Tools
(14,410
)
 
4,729

 
(24,356
)
 
17,354

Total operating gross margin
(20,225
)
 
4,021

 
(33,653
)
 
28,288

General and administrative expense
(7,995
)
 
(9,511
)
 
(17,776
)
 
(20,348
)
Provision for reduction in carrying value of certain assets
—

 
(2,316
)
 
—

 
(2,316
)
Gain (loss) on disposition of assets, net
(2
)
 
(138
)
 
(62
)
 
2,303

Total operating income (loss)
(28,222
)
 
(7,944
)
 
(51,491
)
 
7,927

Interest expense
(12,187
)
 
(11,396
)
 
(23,749
)
 
(22,474
)
Interest income
32

 
19

 
39

 
202

Other income (loss)
(358
)
 
(1,529
)
 
2,127

 
(2,909
)
Loss from continuing operations before income taxes
$
(40,735
)
 
$
(20,850
)
 
$
(73,074
)
 
$
(17,254
)
 
(1)For the six months ended June 30, 2016, our largest customer, ENL, constituted approximately 39.8 percent of our total consolidated revenues and approximately 58.4 percent of our International & Alaska Drilling segment revenues. Excluding reimbursable revenues of $36.9 million, ENL constituted approximately 28.7 percent of our total consolidated revenues and approximately 46.4 percent of our International & Alaska Drilling segment revenues. Our second largest customer, BP, constituted 11.9 percent of our total consolidated revenues and approximately 17.2 percent of our International & Alaska Drilling segment revenues.
For the six months ended June 30, 2015, our largest customer, ENL, constituted approximately 26.0 percent of our total consolidated revenues and approximately 44.3 percent of our International & Alaska Drilling segment revenues. Excluding reimbursable revenues of $39.7 million, ENL constituted approximately 18.1 percent of our total consolidated revenues and approximately 34.0 percent of our International & Alaska Drilling segment revenues.

13


(2)Operating gross margin is calculated as revenues less direct operating expenses, including depreciation and amortization expense.
Note 7 - Accounting for Uncertainty in Income Taxes
We apply the accounting guidance related to accounting for uncertainty in income taxes. This guidance prescribes a recognition threshold and a measurement attribute for the financial statement recognition and measurement of tax positions taken or expected to be taken in a tax return. For those benefits to be recognized, a tax position must be more likely than not to be sustained upon examination by taxing authorities. At June 30, 2016 we had a liability for unrecognized tax benefits of $5.7 million, all of which would favorably impact our effective tax rate upon recognition, primarily related to foreign operations. At December 31, 2015, we had a liability for unrecognized tax benefits of $7.8 million, including $3.6 million of benefits which would favorably impact our effective tax rate upon recognition, primarily related to foreign operations. In addition, we recognize interest and penalties that could be applied to uncertain tax positions in periodic income tax expense. As of June 30, 2016 and December 31, 2015, we had approximately $1.6 million and $3.4 million, respectively, of accrued interest and penalties related to uncertain tax positions.
Note 8 - Income Tax Benefit/Expense
During the second quarter of 2016 we had income tax benefit of $0.9 million compared to income tax benefit of $6.9 million during the second quarter of 2015. The income tax benefit in the second quarter of 2016 was primarily related to the jurisdictional mix of income and loss during the quarter, along with our continued inability to recognize the benefits associated with certain losses as a result of valuation allowances. The income tax benefit in the second quarter of 2015 was primarily related to pre-tax losses generated during that period.
Note 9 - Long-Term Debt
The following table illustrates our debt portfolio as of June 30, 2016 and December 31, 2015:
Dollars in thousands
June 30,
2016
 
December 31,
2015
6.75% Senior Notes, due July 2022
$
360,000

 
$
360,000

7.50% Senior Notes, due August 2020
225,000

 
225,000

Total Principal
585,000

 
585,000

Less: unamortized debt issuance costs
(9,452
)
 
(10,202
)
Total long-term debt
$
575,548

 
$
574,798

6.75% Senior Notes, due July 2022
On January 22, 2014, we issued $360.0 million aggregate principal amount of 6.75% Senior Notes due 2022 (6.75% Notes) pursuant to an Indenture between the Company and The Bank of New York Mellon Trust Company, N.A., as trustee. Net proceeds from the 6.75% Notes offering plus a $40.0 million term loan draw under the Amended and Restated Senior Secured Credit Agreement (2012 Secured Credit Agreement) and cash on hand were utilized to purchase $416.2 million aggregate principal amount of our outstanding 9.125% Senior Notes due 2018 pursuant to a tender and consent solicitation offer commenced on January 7, 2014.
The 6.75% Notes are general unsecured obligations of the Company and rank equal in right of payment with all of our existing and future senior unsecured indebtedness. The 6.75% Notes are jointly and severally guaranteed by all of our subsidiaries that guarantee indebtedness under the Second Amended and Restated Senior Secured Credit Agreement, as amended from time-to-time (2015 Secured Credit Agreement) and our 7.50% Senior Notes due 2020 (7.50% Notes, and collectively with the 6.75% Notes, the Senior Notes). Interest on the 6.75% Notes is payable on January 15 and July 15 of each year, beginning July 15, 2014. Debt issuance costs related to the 6.75% Notes of approximately $7.6 million ($5.9 million net of amortization as of June 30, 2016) are being amortized over the term of the notes using the effective interest rate method.
At any time prior to January 15, 2017, we may redeem up to 35 percent of the aggregate principal amount of the 6.75% Notes at a redemption price of 106.75 percent of the principal amount, plus accrued and unpaid interest to the redemption date, with the net cash proceeds of certain equity offerings by us. 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.

14


The Indenture restricts our ability and the ability of certain subsidiaries to: (i) sell assets, (ii) pay dividends or make other distributions on capital stock or redeem or repurchase capital stock or subordinated indebtedness, (iii) make investments, (iv) incur or guarantee additional indebtedness, (v) create or incur liens, (vi) enter into sale and leaseback transactions, (vii) incur dividend or other payment restrictions affecting subsidiaries, (viii) merge or consolidate with other entities, (ix) enter into transactions with affiliates, and (x) engage in certain business activities. Additionally, the Indenture contains certain restrictive covenants designating certain events as Events of Default. These covenants are subject to a number of important exceptions and qualifications.
7.50% Senior Notes, due August 2020
On July 30, 2013, we issued $225.0 million aggregate principal amount of the 7.50% Notes pursuant to an Indenture between the Company and The Bank of New York Mellon Trust Company, N.A., as trustee. Net proceeds from the 7.50% Notes offering were primarily used to repay the $125.0 million aggregate principal amount of a term loan used to initially finance the ITS Acquisition, to repay $45.0 million of term loan borrowings under the 2012 Secured Credit Agreement, and for general corporate purposes.
The 7.50% Notes are general unsecured obligations of the Company and rank equal in right of payment with all of our existing and future senior unsecured indebtedness. The 7.50% Notes are jointly and severally guaranteed by all of our subsidiaries that guarantee indebtedness under the 2015 Secured Credit Agreement and the 6.75% Notes. Interest on the 7.50% Notes is payable on February 1 and August 1 of each year, beginning February 1, 2014. Debt issuance costs related to the 7.50% Notes of approximately $5.6 million ($3.6 million, net of amortization as of June 30, 2016) are being amortized over the term of the notes using the effective interest rate method.
At any time prior to August 1, 2016, we were entitled to 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. To date we have not made any redemptions. If we experience certain changes in control, we must offer to repurchase the 7.50% Notes at 101.0 percent of the aggregate principal amount, plus accrued and unpaid interest and additional interest, if any, to the date of repurchase.
The Indenture restricts our ability and the ability of certain subsidiaries to: (i) sell assets, (ii) pay dividends or make other distributions on capital stock or redeem or repurchase capital stock or subordinated indebtedness, (iii) make investments, (iv) incur or guarantee additional indebtedness, (v) create or incur liens, (vi) enter into sale and leaseback transactions, (vii) incur dividend or other payment restrictions affecting subsidiaries, (viii) merge or consolidate with other entities, (ix) enter into transactions with affiliates, and (x) engage in certain business activities. Additionally, the Indenture contains certain restrictive covenants designating certain events as Events of Default. These covenants are subject to a number of important exceptions and qualifications.
2015 Secured Credit Agreement
On January 26, 2015 we entered into the 2015 Secured Credit Agreement, which amended and restated the 2012 Secured Credit Agreement. The 2015 Secured Credit Agreement was originally comprised of a $200.0 million revolving credit facility (Revolver) set to mature on January 26, 2020. On June 1, 2015, we executed the first amendment to the 2015 Secured Credit Agreement in order to amend certain provisions regarding the definition of “Change of Control.” On September 29, 2015, we executed the second amendment to the 2015 Secured Credit Agreement to, among other things, (a) amend certain covenant ratios; (b) increase the Applicable Rate for certain higher levels of consolidated leverage to a maximum of 4.00 percent per annum for Eurodollar Rate loans and to 3.00 percent per annum for Base Rate loans; (c) permit multi-year letters of credit up to an aggregate amount of $5.0 million; (d) limit payment prior to September 30, 2017 of certain restricted payments and certain prepayments of unsecured senior notes and other specified forms of indebtedness; and (e) remove the option of the Company, subject to the consent of the lenders, to increase the Credit Agreement up to an additional $75 million. On May 27, 2016, we executed the third amendment to the 2015 Secured Credit Agreement (the Third Amendment), which reduced availability under the Revolver from $200 million to $100 million. Additionally, among other things, the Third Amendment: (a) eliminates the Leverage Ratio covenant until the fourth quarter of 2018 when the covenant is reinstated with the ratio established at 4.25:1.00, and remains at 4.25:1.00 thereafter; (b) eliminates the Consolidated Interest Coverage Ratio covenant until the fourth quarter of 2017 when the covenant is reinstated with the ratio established at 1.00:1.00 and increases by 0.25 each subsequent quarter until reaching 2.00:1.00 in the fourth quarter of 2018, and remains at 2.00:1.00 thereafter; (c) immediately increases the maximum permitted Senior Secured Leverage Ratio from 1.50:1.00 to 2.80:1.00 until it decreases to 2.20:1.00 in the second quarter of 2017, to 1.75:1.00 in the third quarter of 2017, and to 1.50:1.00 in the fourth quarter of 2017 and remains at 1.50:1.00 thereafter; (d) immediately decreases the minimum permitted Asset Coverage Ratio from 1.25:1.00 to 1.10:1.00 until it increases to 1.25: 1.00 in the fourth quarter of 2017 and remains at 1.25:1.00 thereafter; (e) requires that, at any time our Consolidated Cash Balance in U.S. bank accounts is over $50 million, we repay borrowings under the 2015 Secured Credit Agreement until our Consolidated Cash balance is no more than $50 million or all borrowings have been repaid, and (f) allows up to $75 million of Junior Lien Debt.

15


At the time the Third Amendment was executed, the remaining debt issuance costs for the 2015 Secured Credit Agreement totaled approximately $2.2 million. Since the Revolver was reduced by 50 percent, we wrote off approximately $1.1 million in May 2016. We incurred debt issuance costs relating to the Third Amendment of approximately $0.3 million, bringing total debt issuance costs to $1.4 million ($1.3 million, net of amortization as of June 30, 2016) which are being amortized through January 2020, or the term of the Third Amendment, on a straight line basis.
Our obligations under the 2015 Secured Credit Agreement are guaranteed by substantially all of our direct and indirect domestic subsidiaries, other than immaterial subsidiaries and subsidiaries generating revenues primarily outside the United States, each of which has executed guaranty agreements, and are secured by first priority liens on our accounts receivable, specified rigs including barge rigs in the GOM and land rigs in Alaska, certain U.S.-based rental equipment of the Company and its subsidiary guarantors and the equity interests of certain of the Company’s subsidiaries. The 2015 Secured Credit Agreement contains customary affirmative and negative covenants, such as limitations on indebtedness, liens, restrictions on entry into certain affiliate transactions and payments (including payment of dividends) and maintenance of certain ratios and coverage tests. We were in compliance with all covenants contained in the 2015 Secured Credit Agreement as of June 30, 2016.
Our Revolver is available for general corporate purposes and to support letters of credit. Interest on Revolver loans accrues at a Base Rate plus an Applicable Rate or LIBOR plus an Applicable Rate. Revolving loans are available subject to a quarterly asset coverage ratio calculation based on the Orderly Liquidation Value of certain specified rigs including barge rigs in the GOM and land rigs in Alaska, and certain U.S.-based rental equipment of the Company and its subsidiary guarantors and a percentage of eligible domestic accounts receivable. The $30.0 million draw outstanding at the closing of the 2015 Secured Credit Agreement was repaid in full during the first quarter of 2015 with cash on hand. Letters of credit outstanding against the Revolver as of June 30, 2016 totaled $11.8 million. There were no amounts drawn on the Revolver as of June 30, 2016.    
Note 10 - Fair Value of Financial Instruments
Certain of our assets and liabilities are required to be measured at fair value on a recurring basis. For purposes of recording fair value adjustments for certain financial and non-financial assets and liabilities, and determining fair value disclosures, we estimate fair value at a price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants in the principal market for the asset or liability.
The fair value measurement and disclosure requirements of FASB Accounting Standards Codification Topic No. 820, Fair Value Measurement and Disclosures (ASC 820) requires inputs that we categorize using a three-level hierarchy, from highest to lowest level of observable inputs, as follows:
•
Level 1 — Unadjusted quoted prices for identical assets or liabilities in active markets;
•
Level 2 — Direct or indirect observable inputs, including quoted prices or other market data, for similar assets or liabilities in active markets or identical assets or liabilities in less active markets; and
•
Level 3 — Unobservable inputs that require significant judgment for which there is little or no market data.
When multiple input levels are required for a valuation, we categorize the entire fair value measurement according to the lowest level of input that is significant to the entire measurement even though we may also have utilized significant inputs that are more readily observable. The amounts reported in our consolidated balance sheets for cash and cash equivalents, accounts receivable, and accounts payable approximate fair value.

16


Fair value of our debt instruments is determined using Level 2 inputs. Fair values and related carrying values of our debt instruments were as follows for the periods indicated: 
  
June 30, 2016
 
December 31, 2015
Dollars in thousands
Carrying Amount
 
Fair Value
 
Carrying Amount
 
Fair Value
Long-term Debt
 
 
 
 
 
 
 
6.75% Notes
$
360,000

 
$
270,900

 
$
360,000

 
$
246,600

7.50% Notes
225,000

 
172,125

 
225,000

 
171,000

Total Principal
$
585,000

 
$
443,025

 
$
585,000

 
$
417,600

The assets acquired and liabilities assumed in the 2M-Tek Acquisition were recorded at fair value in accordance with U.S. GAAP. Acquisition date fair values represent either Level 2 fair value measurements (current assets and liabilities, property, plant and equipment) or Level 3 fair value measurements (intangible assets).
Market conditions could cause an instrument to be reclassified from Level 1 to Level 2, or Level 2 to Level 3. There were no transfers between levels of the fair value hierarchy or any changes in the valuation techniques used during the six months ended June 30, 2016.  
Note 11 - Commitments and Contingencies
We are a party to various lawsuits and claims arising out of the ordinary course of business. We estimate the range of our liability related to pending litigation when we believe the amount or range of loss can be estimated. We record our best estimate of a loss when the loss is considered probable. When a liability is probable and there is a range of estimated loss with no best estimate in the range, we record the minimum estimated liability related to the lawsuits or claims. As additional information becomes available, we assess the potential liability related to our pending litigation and claims and revise our estimates. Due to uncertainties related to the resolution of lawsuits and claims, the ultimate outcome may differ significantly from our estimates. In the opinion of management and based on liability accruals provided, our ultimate exposure with respect to these pending lawsuits and claims is not expected to have a material adverse effect on our consolidated financial position or cash flows, although they could have a material adverse effect on our results of operations for a particular reporting period.
Customs Agent and Foreign Corrupt Practices Act (FCPA) Settlement
On April 16, 2013, the Company and the Department of Justice (DOJ) entered into a deferred prosecution agreement (DPA), under which the DOJ deferred for three years prosecuting the Company for criminal violations of the anti-bribery provisions of the FCPA relating to the Company’s retention and use of an individual agent in Nigeria with respect to certain customs-related issues, in return for: (i) the Company’s acceptance of responsibility for, and agreement not to contest or contradict the truthfulness of, the statement of facts and allegations that have been filed in the United States District Court for the Eastern District of Virginia concurrently with the DPA; (ii) the Company’s payment of an approximately $11.76 million fine; (iii) the Company’s reaffirming its commitment to compliance with the FCPA and other applicable anti-corruption laws in connection with the Company’s operations, and continuing cooperation with domestic and foreign authorities in connection with the matters that are the subject of the DPA; (iv) the Company’s commitment to continue to address any identified areas for improvement in the Company’s internal controls, policies and procedures relating to compliance with the FCPA and other applicable anti-corruption laws if, and to the extent, not already addressed; and (v) the Company’s agreement to report to the DOJ in writing annually during the term of the DPA regarding remediation of the matters that are the subject of the DPA, implementation of any enhanced internal controls, and any evidence of improper payments the Company may have discovered during the term of the agreement. The DPA provided that as long as the Company remained in compliance with the terms of the DPA throughout its effective period, the charge against the Company would be dismissed with prejudice. The Company also settled a related civil complaint filed by the Securities and Exchange Commission. The third written annual report was filed with the DOJ on April 15, 2016, and the term of the DPA expired on April 23, 2016. On May 20, 2016, the DOJ filed a Motion to Dismiss the case based on its determination that the Company had complied with all of its obligations under the DPA. On the same date, the Court entered an Order dismissing with prejudice the United States’ case against the Company. With the dismissal of the case, the DPA was also terminated.

17


Note 12 - Recent Accounting Pronouncements    
In March 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2016-09, Compensation - Stock Compensation (Topic 718). The objective of this update is to simplify several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. The standard becomes effective for public companies for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years. Early adoption is permitted. We are in the process of assessing the impact of the adoption of ASU 2016-09 on our financial position, results of operations and cash flows.
In March 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842). This update establishes a new lease accounting model for lessees. Upon adoption, a modified retrospective approach is required for leases that exist, or are entered into, after the beginning of the earliest comparative period presented. The standard is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, although early adoption is permitted. We are in the process of assessing the impact of the adoption of ASU 2016-02 on our financial position, results of operations and cash flows. We have not yet determined the effect of the standard on our ongoing financial reporting.
In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers. This ASU supersedes the revenue recognition requirements in Accounting Standards Codification 605 - Revenue Recognition and most industry-specific guidance throughout the Codification. The standard requires that an entity recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services and should be applied retrospectively to each prior reporting period presented or retrospectively with the cumulative effect of initially applying the ASU recognized at the date of initial application. ASU 2014-09 is effective for fiscal years beginning after December 15, 2017. We are in the process of assessing the impact of the adoption of ASU 2014-09 on our financial position, results of operations and cash flows. We have not yet selected a transition method nor have we determined the effect of the standard on our ongoing financial reporting.    

18


Note 13 - Parent, Guarantor, Non-Guarantor Unaudited Consolidating Condensed Financial Statements
Set forth on the following pages are the consolidating condensed financial statements of Parker Drilling. The 2015 Secured Credit Agreement and Senior Notes are fully and unconditionally guaranteed by substantially all of our direct and indirect domestic subsidiaries, other than immaterial subsidiaries and subsidiaries generating revenues primarily outside the United States, subject to the following customary release provisions:
•
in connection with any sale or other disposition of all or substantially all of the assets of that guarantor (including by way of merger or consolidation) to a person that is not (either before or after giving effect to such transaction) a subsidiary of the Company;
•
in connection with any sale of such amount of capital stock as would result in such guarantor no longer being a subsidiary to a person that is not (either before or after giving effect to such transaction) a subsidiary of the Company;
•
if the Company designates any restricted subsidiary that is a guarantor as an unrestricted subsidiary;
•
if the guarantee by a guarantor of all other indebtedness of the Company or any other guarantor is released, terminated or discharged, except by, or as a result of, payment under such guarantee; or
•
upon legal defeasance or covenant defeasance (satisfaction and discharge of the indenture).
There are currently no restrictions on the ability of the restricted subsidiaries to transfer funds to Parker Drilling in the form of cash dividends, loans or advances. Parker Drilling is a holding company with no operations, other than through its subsidiaries. Separate financial statements for each guarantor company are not provided as the Company complies with Rule 3-10(f) of Regulation S-X. All guarantor subsidiaries are owned 100 percent by the parent company.
We are providing unaudited consolidating condensed financial information of the parent, Parker Drilling, the guarantor subsidiaries, and the non-guarantor subsidiaries as of June 30, 2016 and December 31, 2015 and for the three and six months ended June 30, 2016 and 2015, respectively. The consolidating condensed financial statements present investments in both consolidated and unconsolidated subsidiaries using the equity method of accounting.
Upon the closing of our 2015 Secured Credit Agreement, one of our subsidiaries was released as a guarantor subsidiary and is now classified as a non-guarantor subsidiary. In accordance with the guidance Topic No. 810, Consolidation (ASC 810), we have retrospectively updated the unaudited consolidating condensed financial information as of December 31, 2015 and June 30, 2015.

19


  
PARKER DRILLING COMPANY AND SUBSIDIARIES
CONSOLIDATING CONDENSED BALANCE SHEET
(Dollars in Thousands)
(Unaudited)
 
 
June 30, 2016
 
Parent
 
Guarantor
 
Non-Guarantor
 
Eliminations
 
Consolidated
ASSETS
Current assets:
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
$
55,280

 
$
12,192

 
$
41,562

 
$
—

 
$
109,034

Accounts and notes receivable, net
—

 
34,853

 
118,336

 
—

 
153,189

Rig materials and supplies
—

 
(6,009
)
 
38,624

 
—

 
32,615

Other current assets
—

 
8,601

 
18,204

 
—

 
26,805

Total current assets
55,280

 
49,637

 
216,726

 
—

 
321,643

Property, plant and equipment, net
(19
)
 
502,191

 
244,845

 
—

 
747,017

Goodwill
—

 
6,708

 
—

 
—

 
6,708

Intangible assets, net
—

 
10,587

 
805

 
—

 
11,392

Investment in subsidiaries and intercompany advances
3,032,953

 
2,889,755

 
3,498,240

 
(9,420,948
)
 
—

Other noncurrent assets
(151,632
)
 
207,566

 
550,882

 
(480,805
)
 
126,011

Total assets
$
2,936,582

 
$
3,666,444

 
$
4,511,498

 
$
(9,901,753
)
 
$
1,212,771

 
 
 
 
 
 
 
 
 
 
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
 
 
 
 
 
 
 
 
 
Accounts payable and accrued liabilities
$
114,217

 
$
44,382

 
$
567,968

 
$
(617,476
)
 
$
109,091

Accrued income taxes
30,910

 
(15,019
)
 
(10,114
)
 
—

 
5,777

Total current liabilities
145,127

 
29,363

 
557,854

 
(617,476
)
 
114,868

Long-term debt, net
575,548

 
—

 
—

 
—

 
575,548

Other long-term liabilities
2,867

 
7,708

 
4,474

 
—

 
15,049

Long-term deferred tax liability
(29
)
 
77,394

 
(890
)
 
—

 
76,475

Intercompany payables
1,779,740

 
1,417,482

 
2,018,050

 
(5,215,272
)
 
—

Total liabilities
2,503,253

 
1,531,947

 
2,579,488

 
(5,832,748
)
 
781,940

Total equity
433,329

 
2,134,497

 
1,932,010

 
(4,069,005
)
 
430,831

Total liabilities and stockholders’ equity
$
2,936,582

 
$
3,666,444

 
$
4,511,498

 
$
(9,901,753
)
 
$
1,212,771


20



PARKER DRILLING COMPANY AND SUBSIDIARIES
CONSOLIDATING CONDENSED BALANCE SHEET
(Dollars in Thousands)
(Unaudited)
 
 
December 31, 2015
 
Parent
 
Guarantor
 
Non-Guarantor
 
Eliminations
 
Consolidated
ASSETS
Current assets:
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
$
73,985

 
$
13,854

 
$
46,455

 
$
—

 
$
134,294

Accounts and notes receivable, net
—

 
42,261

 
132,844

 
—

 
175,105

Rig materials and supplies
—

 
(4,744
)
 
39,681

 
—

 
34,937

Other current assets
—

 
5,982

 
16,423

 
—

 
22,405

Total current assets
73,985

 
57,353

 
235,403

 
—

 
366,741

Property, plant and equipment, net
(19
)
 
543,346

 
262,514

 
—

 
805,841

Goodwill
—

 
6,708

 
—

 
—

 
6,708

Intangible assets, net
—

 
11,740

 
1,637

 
—

 
13,377

Investment in subsidiaries and intercompany advances
3,057,220

 
2,770,501

 
3,319,702

 
(9,147,423
)
 
—

Other noncurrent assets
(234,786
)
 
312,790

 
265,995

 
(169,964
)
 
174,035

Total assets
$
2,896,400

 
$
3,702,438

 
$
4,085,251

 
$
(9,317,387
)
 
$
1,366,702

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
 
 
 
 
 
 
 
 
 
Accounts payable and accrued liabilities
$
84,456

 
$
56,382

 
$
295,439

 
$
(306,574
)
 
$
129,703

Accrued income taxes
9,900

 
2,111

 
(5,593
)
 
—

 
6,418

Total current liabilities
94,356

 
58,493

 
289,846

 
(306,574
)
 
136,121

Long-term debt, net
574,798

 
—

 
—

 
—

 
574,798

Other long-term liabilities
2,868

 
7,446

 
8,303

 
—

 
18,617

Long-term deferred tax liability
(29
)
 
69,679

 
(996
)
 
—

 
68,654

Intercompany payables
1,656,968

 
1,401,510

 
1,864,671

 
(4,923,149
)
 
—

Total liabilities
2,328,961

 
1,537,128

 
2,161,824

 
(5,229,723
)
 
798,190

Total equity
567,439

 
2,165,310

 
1,923,427

 
(4,087,664
)
 
568,512

Total liabilities and stockholders’ equity
$
2,896,400

 
$
3,702,438

 
$
4,085,251

 
$
(9,317,387
)
 
$
1,366,702



21



PARKER DRILLING COMPANY AND SUBSIDIARIES
CONSOLIDATING CONDENSED STATEMENT OF OPERATIONS
(Dollars in Thousands)
(Unaudited)

 
Three Months Ended June 30, 2016
 
Parent
 
Guarantor
 
Non-Guarantor
 
Eliminations
 
Consolidated
Total revenues
$
—

 
$
34,586

 
$
88,895

 
$
(18,194
)
 
$
105,287

Operating expenses
—

 
25,577

 
81,812

 
(18,194
)
 
89,195

Depreciation and amortization
—

 
23,314

 
13,003

 
—

 
36,317

Total operating gross margin
—

 
(14,305
)
 
(5,920
)
 
—

 
(20,225
)
General and administration expense (1)
(113
)
 
(7,828
)
 
(54
)
 
—

 
(7,995
)
Gain (Loss) on disposition of assets, net
—

 
209

 
(211
)
 
—

 
(2
)
Total operating income (loss)
(113
)
 
(21,924
)
 
(6,185
)
 
—

 
(28,222
)
Other income and (expense):
 
 
 
 
 
 
 
 
 
Interest expense
(12,896
)
 
(44
)
 
(2,290
)
 
3,043

 
(12,187
)
Interest income
191

 
180

 
2,704

 
(3,043
)
 
32

Other
—

 
(11
)
 
(347
)
 
—

 
(358
)
Equity in net earnings of subsidiaries
(24,568
)
 
—

 
—

 
24,568

 
—

Total other income (expense)
(37,273
)
 
125

 
67

 
24,568

 
(12,513
)
Income (loss) before income taxes
(37,386
)
 
(21,799
)
 
(6,118
)
 
24,568

 
(40,735
)
Total income tax expense (benefit)
2,438

 
(5,297
)
 
1,946

 
—

 
(913
)
Net income (loss) attributable to controlling interest
$
(39,824
)
 
$
(16,502
)
 
$
(8,064
)
 
$
24,568

 
$
(39,822
)

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

22



PARKER DRILLING COMPANY AND SUBSIDIARIES
CONSOLIDATING CONDENSED STATEMENT OF OPERATIONS
(Dollars in Thousands)
(Unaudited)
 
Three Months Ended June 30, 2015
 
Parent
 
Guarantor
 
Non-Guarantor
 
Eliminations
 
Consolidated
Total revenues
$
—

 
$
63,276

 
$
162,703

 
$
(40,038
)
 
$
185,941

Operating expenses
—

 
35,627

 
147,980

 
(40,038
)
 
143,569

Depreciation and amortization
—

 
23,958

 
14,393

 
—

 
38,351

Total operating gross margin
—

 
3,691

 
330

 
—

 
4,021

General and administration expense (1)
(891
)
 
(12,924
)
 
4,304

 
—

 
(9,511
)
Provision for reduction in carrying value of certain assets
—

 
—

 
(2,316
)
 
—

 
(2,316
)
Gain on disposition of assets, net
—

 
(6
)
 
(132
)
 
—

 
(138
)
Total operating income (loss)
(891
)
 
(9,239
)
 
2,186

 
—

 
(7,944
)
Other income and (expense):
 
 
 
 
 
 
 
 
 
Interest expense
(11,066
)
 
(323
)
 
(3,010
)
 
3,003

 
(11,396
)
Interest income
165

 
3

 
2,854

 
(3,003
)
 
19

Other
—

 
11

 
(1,540
)
 
—

 
(1,529
)
Equity in net earnings of subsidiaries
(8,392
)
 
—

 
—

 
8,392

 
—

Total other income (expense)
(19,293
)
 
(309
)
 
(1,696
)
 
8,392

 
(12,906
)
Income (loss) before income taxes
(20,184
)
 
(9,548
)
 
490

 
8,392

 
(20,850
)
Income tax expense (benefit)
(6,155
)
 
(2,361
)
 
1,600

 
—

 
(6,916
)
Net income (loss)
(14,029
)
 
(7,187
)
 
(1,110
)
 
8,392

 
(13,934
)
Less: Net income attributable to noncontrolling interest
—

 
—

 
95

 
—

 
95

Net income (loss) attributable to controlling interest
$
(14,029
)
 
$
(7,187
)
 
$
(1,205
)
 
$
8,392

 
$
(14,029
)

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
























23




PARKER DRILLING COMPANY AND SUBSIDIARIES
CONSOLIDATING CONDENSED STATEMENT OF OPERATIONS
(Dollars in Thousands)
(Unaudited)

 
Six Months Ended June 30, 2016
 
Parent
 
Guarantor
 
Non-Guarantor
 
Eliminations
 
Consolidated
Total revenues
$
—

 
$
81,968

 
$
195,372

 
$
(41,550
)
 
$
235,790

Operating expenses
—

 
58,413

 
180,449

 
(41,550
)
 
197,312

Depreciation and amortization
—

 
46,439

 
25,692

 
—

 
72,131

Total operating gross margin
—

 
(22,884
)
 
(10,769
)
 
—

 
(33,653
)
General and administration expense (1)
(200
)
 
(17,440
)
 
(136
)
 
—

 
(17,776
)
Gain (Loss) on disposition of assets, net
—

 
153

 
(215
)
 
—

 
(62
)
Total operating income (loss)
(200
)
 
(40,171
)
 
(11,120
)
 
—

 
(51,491
)
Other income and (expense):
 
 
 
 
 
 
 
 
 
Interest expense
(24,752
)
 
(481
)
 
(5,150
)
 
6,634

 
(23,749
)
Interest income
395

 
359

 
5,919

 
(6,634
)
 
39

Other
—

 
473

 
1,654

 
—

 
2,127

Equity in net earnings of subsidiaries
(40,793
)
 
—

 
—

 
40,793

 
—

Total other income (expense)
(65,150
)
 
351

 
2,423

 
40,793

 
(21,583
)
Income (loss) before income taxes
(65,350
)
 
(39,820
)
 
(8,697
)
 
40,793

 
(73,074
)
Total income tax expense (benefit)
70,307

 
(9,004
)
 
1,280

 
—

 
62,583

Net income (loss) attributable to controlling interest
$
(135,657
)
 
$
(30,816
)
 
$
(9,977
)
 
$
40,793

 
$
(135,657
)

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


























24


PARKER DRILLING COMPANY AND SUBSIDIARIES
CONSOLIDATING CONDENSED STATEMENT OF OPERATIONS
(Dollars in Thousands)
(Unaudited)

 
Six Months Ended June 30, 2015
 
Parent
 
Guarantor
 
Non-Guarantor
 
Eliminations
 
Consolidated
Total revenues
$
—

 
$
142,672

 
$
313,633

 
$
(66,288
)
 
$
390,017

Operating expenses
—

 
79,772

 
269,355

 
(66,288
)
 
282,839

Depreciation and amortization
—

 
47,268

 
31,622

 
—

 
78,890

Total operating gross margin
—

 
15,632

 
12,656

 
—

 
28,288

General and administration expense (1)
(1,004
)
 
(23,039
)
 
3,695

 
—

 
(20,348
)
Provision for reduction in carrying value of certain assets
—

 
—

 
(2,316
)
 
—

 
(2,316
)
Gain (Loss) on disposition of assets, net
—

 
45

 
2,258

 
—

 
2,303

Total operating income (loss)
(1,004
)
 
(7,362
)
 
16,293

 
—

 
7,927

Other income and (expense):
 
 
 
 
 
 
 
 
 
Interest expense
(22,125
)
 
(340
)
 
(3,338
)
 
3,329

 
(22,474
)
Interest income
583

 
5

 
2,943

 
(3,329
)
 
202

Other
—

 
20

 
(2,929
)
 
—

 
(2,909
)
Equity in net earnings of subsidiaries
597

 
—

 
—

 
(597
)
 
—

Total other income (expense)
(20,945
)
 
(315
)
 
(3,324
)
 
(597
)
 
(25,181
)
Income (loss) before income taxes
(21,949
)
 
(7,677
)
 
12,969

 
(597
)
 
(17,254
)
Total income tax expense (benefit)
(11,142
)
 
(2,809
)
 
6,853

 
—

 
(7,098
)
Net income (loss)
(10,807
)
 
(4,868
)
 
6,116

 
(597
)
 
(10,156
)
Less: Net income attributable to noncontrolling interest
—

 
—

 
651

 
—

 
651

Net income (loss) attributable to controlling interest
$
(10,807
)
 
$
(4,868
)
 
$
5,465

 
$
(597
)
 
$
(10,807
)

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


25



PARKER DRILLING COMPANY AND SUBSIDIARIES
CONSOLIDATING CONDENSED STATEMENT OF COMPREHENSIVE INCOME (LOSS)
(Dollars in Thousands)
(Unaudited)

 
Three Months Ended June 30, 2016
 
Parent
 
Guarantor
 
Non-Guarantor
 
Eliminations
 
Consolidated
Comprehensive income:
 
 
 
 
 
 
 
 
 
Net income (loss)
$
(39,824
)
 
$
(16,502
)
 
$
(8,064
)
 
$
24,568

 
$
(39,822
)
Other comprehensive income (loss), net of tax:
 
 
 
 
 
 
 
 
 
Currency translation difference on related borrowings
—

 
—

 
(307
)
 
—

 
(307
)
Currency translation difference on foreign currency net investments
—

 
—

 
(2,228
)
 
—

 
(2,228
)
Total other comprehensive income (loss), net of tax:
—

 
—

 
(2,535
)
 
—

 
(2,535
)
Comprehensive income (loss) attributable to controlling interest
$
(39,824
)
 
$
(16,502
)
 
$
(10,599
)
 
$
24,568

 
$
(42,357
)



PARKER DRILLING COMPANY AND SUBSIDIARIES
CONSOLIDATING CONDENSED STATEMENT OF COMPREHENSIVE INCOME (LOSS)
(Dollars in Thousands)
(Unaudited)

 
Three Months Ended June 30, 2015
 
Parent
 
Guarantor
 
Non-Guarantor
 
Eliminations
 
Consolidated
Comprehensive income:
 
 
 
 
 
 
 
 
 
Net income (loss)
$
(14,029
)
 
$
(7,187
)
 
$
(1,110
)
 
$
8,392

 
$
(13,934
)
Other comprehensive income (loss), net of tax:
 
 
 
 
 
 
 
 
 
Currency translation difference on related borrowings
—

 
—

 
647

 
—

 
647

Currency translation difference on foreign currency net investments
—

 
—

 
1,723

 
—

 
1,723

Total other comprehensive income (loss), net of tax:
—

 
—

 
2,370

 
—

 
2,370

Comprehensive income (loss)
(14,029
)
 
(7,187
)
 
1,260

 
8,392

 
(11,564
)
Comprehensive loss attributable to noncontrolling interest
—

 
—

 
(95
)
 
—

 
(95
)
Comprehensive income (loss) attributable to controlling interest
$
(14,029
)
 
$
(7,187
)
 
$
1,165

 
$
8,392

 
$
(11,659
)







PARKER DRILLING COMPANY AND SUBSIDIARIES
CONSOLIDATING CONDENSED STATEMENT OF COMPREHENSIVE INCOME (LOSS)
(Dollars in Thousands)

26


(Unaudited)

 
Six Months Ended June 30, 2016
 
Parent
 
Guarantor
 
Non-Guarantor
 
Eliminations
 
Consolidated
Comprehensive income:
 
 
 
 
 
 
 
 
 
Net income (loss)
$
(135,657
)
 
$
(30,816
)
 
$
(9,977
)
 
$
40,793

 
$
(135,657
)
Other comprehensive income (loss), net of tax:
 
 
 
 
 
 
 
 
 
Currency translation difference on related borrowings
—

 
—

 
195

 
—

 
195

Currency translation difference on foreign currency net investments
—

 
—

 
(3,766
)
 
—

 
(3,766
)
Total other comprehensive income (loss), net of tax:
—

 
—

 
(3,571
)
 
—

 
(3,571
)
Comprehensive income (loss) attributable to controlling interest
$
(135,657
)
 
$
(30,816
)
 
$
(13,548
)
 
$
40,793

 
$
(139,228
)



PARKER DRILLING COMPANY AND SUBSIDIARIES
CONSOLIDATING CONDENSED STATEMENT OF COMPREHENSIVE INCOME (LOSS)
(Dollars in Thousands)
(Unaudited)

 
Six Months Ended June 30, 2015
 
Parent
 
Guarantor
 
Non-Guarantor
 
Eliminations
 
Consolidated
Comprehensive income:
 
 
 
 
 
 
 
 
 
Net income (loss)
$
(10,807
)
 
$
(4,868
)
 
$
6,116

 
$
(597
)
 
$
(10,156
)
Other comprehensive income (loss), net of tax:
 
 
 
 
 
 
 
 
 
Currency translation difference on related borrowings
—

 
—

 
(1,023
)
 
—

 
(1,023
)
Currency translation difference on foreign currency net investments
—

 
—

 
874

 
—

 
874

Total other comprehensive income (loss), net of tax:
—

 
—

 
(149
)
 
—

 
(149
)
Comprehensive income (loss)
(10,807
)
 
(4,868
)
 
5,967

 
(597
)
 
(10,305
)
Comprehensive (loss) attributable to noncontrolling interest
—

 
—

 
(489
)
 
—

 
(489
)
Comprehensive income (loss) attributable to controlling interest
$
(10,807
)
 
$
(4,868
)
 
$
5,478

 
$
(597
)
 
$
(10,794
)







27



PARKER DRILLING COMPANY AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
(Unaudited)
 
 
Six Months Ended June 30, 2016
 
Parent
 
Guarantor
 
Non-Guarantor
 
Eliminations
 
Consolidated
Cash flows from operating activities:
 
 
 
 
 
 
 
 
 
Net income (loss)
$
(135,657
)
 
$
(30,816
)
 
$
(9,977
)
 
$
40,793

 
$
(135,657
)
Adjustments to reconcile net income (loss):
 
 
 
 
 
 
 
 
 
Depreciation and amortization
—

 
46,439

 
25,692

 
—

 
72,131

Accretion of contingent consideration
—

 
419

 
—

 
—

 
419

Loss on debt modification
1,088

 
—

 
—

 
—

 
1,088

Gain on disposition of assets
—

 
(153
)
 
215

 
—

 
62

Deferred income tax expense
49,167

 
9,569

 
569

 
—

 
59,305

Expenses not requiring cash
2,693

 
(282
)
 
(7,637
)
 
—

 
(5,226
)
Equity in net earnings of subsidiaries
40,793

 
—

 
—

 
(40,793
)
 
—

Change in assets and liabilities:
 
 
 
 
 
 
 
 
 
Accounts and notes receivable
—

 
7,755

 
14,564

 
—

 
22,319

Other assets
(103,035
)
 
102,496

 
(2,453
)
 
—

 
(2,992
)
Accounts payable and accrued liabilities
3,281

 
(5,737
)
 
(4,406
)
 
—

 
(6,862
)
Accrued income taxes
21,711

 
(17,830
)
 
(7,866
)
 
—

 
(3,985
)
Net cash provided by (used in) operating activities
(119,959
)
 
111,860

 
8,701

 
—

 
602

 
 
 
 
 
 
 
 
 
 
Cash flows from investing activities:
 
 
 
 
 
 
 
 
 
Capital expenditures
—

 
(7,499
)
 
(8,758
)
 
—

 
(16,257
)
Proceeds from the sale of assets
—

 
121

 
1,266

 
—

 
1,387

Net cash provided by (used in) investing activities
—

 
(7,378
)
 
(7,492
)
 
—

 
(14,870
)
 
 
 
 
 
 
 
 
 
 
Cash flows from financing activities:
 
 
 
 
 
 
 
 
 
Payment for noncontrolling interest
(3,375
)
 
—

 
—

 
—

 
(3,375
)
Payment of contingent consideration
—

 
(6,000
)
 
—

 
—

 
(6,000
)
Excess tax benefit from stock-based compensation
(1,617
)
 
—

 
—

 
—

 
(1,617
)
Intercompany advances, net
106,246

 
(100,144
)
 
(6,102
)
 
—

 
—

Net cash provided by (used in) financing activities
101,254

 
(106,144
)
 
(6,102
)
 
—

 
(10,992
)
 
 
 
 
 
 
 
 
 
 
Net change in cash and cash equivalents
(18,705
)
 
(1,662
)
 
(4,893
)
 
—

 
(25,260
)
Cash and cash equivalents at beginning of year
73,985

 
13,854

 
46,455

 
—

 
134,294

Cash and cash equivalents at end of year
$
55,280

 
$
12,192

 
$
41,562

 
$
—

 
$
109,034




28



PARKER DRILLING COMPANY AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
(Unaudited)
 
Six Months Ended June 30, 2015
 
Parent
 
Guarantor
 
Non-Guarantor
 
Eliminations
 
Consolidated
Cash flows from operating activities:
 
 
 
 
 
 
 
 
 
Net income (loss)
$
(10,807
)
 
$
(4,868
)
 
$
6,116

 
$
(597
)
 
$
(10,156
)
Adjustments to reconcile net income (loss)
 
 
 
 
 
 
 
 
 
Depreciation and amortization
—

 
47,268

 
31,622

 
—

 
78,890

Accretion of contingent consideration
—

 
—

 
306

 
—

 
306

Provision for reduction in carrying value of certain assets
—

 
—

 
2,316

 
—

 
2,316

Gain on disposition of assets
—

 
(45
)
 
(2,258
)
 
—

 
(2,303
)
Deferred income tax expense
(22,414
)
 
6,574

 
(1,286
)
 
—

 
(17,126
)
Expenses not requiring cash
4,039

 
441

 
828

 
—

 
5,308

Equity in net earnings of subsidiaries
(597
)
 
—

 
—

 
597

 
—

Change in assets and liabilities:
 
 
 
 
 
 
 
 
 
Accounts and notes receivable
—

 
27,778

 
11,905

 
—

 
39,683

Other assets
(77,427
)
 
59,964

 
10,111

 
—

 
(7,352
)
Accounts payable and accrued liabilities
29

 
14,890

 
(156
)
 
—

 
14,763

Accrued income taxes
2,146

 
229

 
(3,611
)
 
—

 
(1,236
)
Net cash provided by (used in) operating activities
(105,031
)
 
152,231

 
55,893

 
—

 
103,093

 
 
 
 
 
 
 
 
 
 
Cash flows from investing activities:
 
 
 
 
 
 
 
 
 
Capital expenditures
—

 
(37,794
)
 
(16,811
)
 
—

 
(54,605
)
Proceeds from the sale of assets
—

 
82

 
206

 
—

 
288

Proceeds from insurance settlements
—

 
—

 
2,500

 
—

 
2,500

Acquisitions, net of cash acquired
—

 
(10,431
)
 
—

 
—

 
(10,431
)
Net cash provided by (used in) investing activities
—

 
(48,143
)
 
(14,105
)
 
—

 
(62,248
)
 
 
 
 
 
 
 
 
 
 
Cash flows from financing activities:
 
 
 
 
 
 
 
 
 
Repayments of long-term debt
(30,000
)
 
—

 
—

 
—

 
(30,000
)
Payment of debt issuance costs
(1,359
)
 
—

 
—

 
—

 
(1,359
)
Excess tax benefit from stock-based compensation
(999
)
 
—

 
—

 
—

 
(999
)
Intercompany advances, net
142,814

 
(97,138
)
 
(45,676
)
 
—

 
—

Net cash provided by (used in) financing activities
110,456

 
(97,138
)
 
(45,676
)
 
—

 
(32,358
)
 
 
 
 
 
 
 
 
 
 
Net change in cash and cash equivalents
5,425

 
6,950

 
(3,888
)
 
—

 
8,487

Cash and cash equivalents at beginning of year
36,728

 
13,546

 
58,182

 
—

 
108,456

Cash and cash equivalents at end of year
$
42,153

 
$
20,496

 
$
54,294

 
$
—

 
$
116,943




29


Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Management’s discussion and analysis (MD&A) should be read in conjunction with Item 1. Financial Statements of this quarterly report on Form 10-Q and with our Annual Report on Form 10-K for the year ended December 31, 2015 (2015 Form 10-K).
DISCLOSURE NOTE REGARDING FORWARD-LOOKING STATEMENTS
This Form 10-Q contains statements that are “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the Exchange Act). All statements contained in this Form 10-Q, other than statements of historical facts, are forward-looking statements for purposes of these provisions, including any statements regarding:
•stability or volatility of prices and demand for oil and natural gas;
•levels of oil and natural gas exploration and production activities;
•demand for contract drilling and drilling-related services and demand for rental tools and related services;
•our future operating results and profitability;
•our future rig utilization, dayrates and rental tools activity;
•
entering into new, or extending existing, drilling or rental contracts and our expectations concerning when operations will commence under such contracts;
•entry into new markets or potential exit from existing markets;
•growth through acquisitions of companies or assets;
•organic growth of our operations;
•
construction or upgrades of rigs or drilling services equipment and expectations regarding when such rigs or equipment will commence operations;
•
capital expenditures for acquisition of rental tools, rigs, construction of new rigs or drilling services equipment or major upgrades to existing rigs or equipment;
•entering into joint venture agreements;
•our future liquidity;
•sale or potential sale of assets or references to assets held for sale;
•availability and sources of funds to refinance our debt and expectations of when debt will be reduced;
•the outcome of pending or future legal proceedings, investigations, tax assessments and other claims;
•the availability of insurance coverage for pending or future claims;
•the enforceability of contractual indemnification in relation to pending or future claims; and
•compliance with covenants under our debt agreements.
In some cases, you can identify these statements by forward-looking words such as “anticipate,” “believe,” “could,” “estimate,” “expect,” “intend,” “outlook,” “may,” “should,” “will” and “would” or similar words. Forward-looking statements are based on certain assumptions and analyses we make in light of our experience and perception of historical trends, current conditions, expected future developments and other factors we believe are relevant. Although we believe that our assumptions are reasonable based on information currently available, those assumptions are subject to significant risks and uncertainties, many of which are outside of our control. The following factors, as well as any other cautionary language included in this Form 10-Q, provide examples of risks, uncertainties and events that may cause our actual results to differ materially from the expectations we describe in our forward-looking statements:
•
fluctuations in the market prices of oil and natural gas, including the inability or unwillingness of our customers to fund drilling programs in low price cycles;

30


•
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;
•
U.S. credit market volatility resulting from a restrictive regulatory environment imposed upon lenders due to their over exposure to the energy industry;
•the U.S. economy and the demand for oil and natural gas;
•low oil and natural gas prices that could adversely affect our drilling services and rental tools services businesses;
•worldwide demand for oil;
•
imposition of trade restrictions, including additional economic sanctions and export/re export controls affecting our business operations in Russia;
•unanticipated operating hazards and uninsured risks;
•political instability, terrorism or war;
•
governmental regulations, including changes in accounting rules or tax laws that adversely affect the cost of doing business or our ability to remit funds to the U.S.;
•changes in the tax laws that would allow double taxation on foreign sourced income;
•the outcome of investigations into possible violations of laws;
•adverse environmental events;
•adverse weather conditions;
•global health concerns;
•changes in the concentration of customer and supplier relationships;
•ability of our customers and suppliers to obtain financing for their operations;
•ability of our customers to fund drilling plans;
•unexpected cost increases for new construction and upgrade and refurbishment projects;
•delays in obtaining components for capital projects and in ongoing operational maintenance and equipment certifications;
•shortages of skilled labor;
•unanticipated cancellation of contracts by customers or operators;
•breakdown of equipment;
•other operational problems including delays in start-up or commissioning of rigs;
•changes in competition;
•any failure to realize expected benefits from acquisitions;
•the effect of litigation and contingencies; and
•
other similar factors, some of which are discussed in documents referred to or incorporated by reference into this Form 10-Q and our other reports and filings with the Securities and Exchange Commission (SEC).
Each forward-looking statement speaks only as of the date of this Form 10-Q, and we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. You should be aware that the occurrence of the events described in these risk factors and elsewhere in this Form 10-Q could have a material adverse effect on our business, results of operations, financial condition and cash flows.

31


Executive Overview and Outlook
The oil and gas industry is highly cyclical. Activity levels are driven by traditional energy industry activity indicators, which include current and expected commodity prices, drilling rig counts, footage drilled, well counts, and our customers’ spending levels allocated towards exploratory and development drilling.
Historical market indicators are listed below:
 
 
Six Months Ended June 30,
 
 
 
 
 
2016
 
2015
 
% Change
 
Worldwide Rig Count (1)
 
 
 
 
 
 
 
U.S. (land and offshore)
 
488

 
1,145

 
(57
)%
 
International (2)
 
979

 
1,215

 
(19
)%
 
Commodity Prices (3)
 
 
 
 
 

 
Crude Oil (United Kingdom Brent)
 
$
41.21

 
59.35

 
(31
)%
 
Crude Oil (West Texas Intermediate)
 
$
39.78

 
53.34

 
(25
)%
 
Natural Gas (Henry Hub)
 
$
2.12

 
2.77

 
(23
)%
 
(1) Estimate of drilling activity measured by the average active rig count for the periods indicated - Source: Baker Hughes Incorporated Rig Count
(2) Excludes Canadian Rig Count.
(3) Average daily commodity prices for the periods indicated based on NYMEX front-month composite energy prices.
The current business environment continues to be challenging despite signs that industry fundamentals are beginning to improve. Supply and demand dynamics are starting to come into balance but historic high global inventories persist and will likely act as a headwind against additional commodity price increases and increased capital spending by our customers in the near-term.
We anticipate results in our Rental Tools segment to stabilize in the short-term. As of July 15, 2016, U.S. rig count had increased 6 out of 7 weeks and was up over 10% since the low of 404 rigs set on May 27, 2016. Our Rental Tools Tubular Goods Utilization Index declined from 32.5 in April to 29.7 in May before recovering to 32.0 in June. This was the first increase in the index this year. While U.S. drilling activity is showing signs of improvement, we do expect further declines in U.S. offshore activity. Internationally, we expect stabilization in our business as project start-ups begin in the third quarter. We also anticipate lower operating expenses across the segment.
For our U.S. (Lower 48) Drilling segment, we do not anticipate any material changes in activity levels at current commodity prices, so we expect to see a continuation of low barge utilization levels and dayrates. Activity in the inland waters of the Gulf of Mexico remains muted as operators continue to defer spending due to limited access to capital and uncertainty in commodity prices.  In the International & Alaska Drilling Segment, we expect activity to remain low through the second half of 2016 and results to be impacted by lower realized dayrates attributable to price concessions, more rigs operating in standby mode, and the completion of a project services engagement.
Although we do not know the depth or duration of this downcycle, we have taken steps to align resources with the ongoing market downturn by lowering our cost base, sustaining our utilization, and managing our cash and liquidity. We will continue to adjust and adapt to the business environment and market conditions, while remaining opportunistic and positioning the Company for longer-term growth.

32


Results of Operations
Our business is comprised of two business lines: (1) Drilling Services and (2) Rental Tools Services. We report our Rental Tools Services business as one reportable segment (Rental Tools) and report our Drilling Services business as two reportable segments: (1) U.S. (Lower 48) Drilling and (2) International & Alaska Drilling. We eliminate inter-segment revenues and expenses.
We analyze financial results for each of our reportable segments. The reportable segments presented are consistent with our reportable segments discussed in Note 6 to our consolidated condensed financial statements. We monitor our reporting segments based on several criteria, including operating gross margin and operating gross margin excluding depreciation and amortization. Operating gross margin excluding depreciation and amortization is computed as revenues less direct operating expenses, and excludes depreciation and amortization expense, where applicable. Operating gross margin percentages are computed as operating gross margin as a percent of revenues. The operating gross margin excluding depreciation and amortization amounts and percentages should not be used as a substitute for those amounts reported under accounting policies generally accepted in the United States (U.S. GAAP), but should be viewed in addition to the Company’s reported results prepared in accordance with U.S. GAAP. Management believes this information may provide additional, meaningful comparisons between current results and results of prior periods to users of this financial information.
Three Months Ended June 30, 2016 Compared with Three Months Ended June 30, 2015
Revenues decreased $80.6 million, or 43.4 percent, to $105.3 million for the three months ended June 30, 2016 as compared to revenues of $185.9 million for the three months ended June 30, 2015. Operating gross margin decreased $24.2 million, to a loss of $20.2 million, for the three months ended June 30, 2016 as compared to income of $4.0 million for the three months ended June 30, 2015.
    The following is an analysis of our operating results for the comparable periods by reportable segment:
 
Three Months Ended June 30,
Dollars in Thousands
2016
 
2015
 
 
Revenues:
 
Drilling Services:
 
 
 
 
 
 
 
U.S. (Lower 48) Drilling
$
1,065

 
1
%
 
$
6,848

 
4
%
International & Alaska Drilling
71,926

 
68
%
 
114,969

 
62
%
Total Drilling Services
72,991

 
69
%
 
121,817

 
66
%
Rental Tools
32,296

 
31
%
 
64,124

 
34
%
Total revenues
105,287

 
100
%
 
185,941

 
100
%
Operating gross margin (loss) excluding depreciation and amortization:
 
 
 
 
 
 
 
Drilling Services:
 
 
 
 
 
 
 
U.S. (Lower 48) Drilling
(3,902
)
 
n/m

 
(1,981
)
 
n/m

International & Alaska Drilling
17,816

 
25
%
 
22,640

 
20
%
Total Drilling Services
13,914

 
19
%
 
20,659

 
17
%
Rental Tools
2,178

 
7
%
 
21,713

 
34
%
Total operating gross margin excluding depreciation and amortization
16,092

 
15
%
 
42,372

 
23
%
Depreciation and amortization
(36,317
)
 
 
 
(38,351
)
 
 
Total operating gross margin
(20,225
)
 
 
 
4,021

 
 
General and administrative expense
(7,995
)
 
 
 
(9,511
)
 
 
Provision for reduction in carrying value of certain assets
—

 
 
 
(2,316
)
 
 
Loss on disposition of assets, net
(2
)
 
 
 
(138
)
 
 
Total operating loss
$
(28,222
)
 
 
 
$
(7,944
)
 
 


33


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 June 30, 2016
 
 
 
 
 
 
 
Operating gross margin (1)
$
(9,011
)
 
$
3,196

 
$
(14,410
)
 
$
(20,225
)
Depreciation and amortization
5,109

 
14,620

 
16,588

 
36,317

Operating gross margin excluding depreciation and amortization
$
(3,902
)
 
$
17,816

 
$
2,178

 
$
16,092

Three Months Ended June 30, 2015
 
 
 
 
 
 
 
Operating gross margin (1)
$
(7,552
)
 
$
6,844

 
$
4,729

 
$
4,021

Depreciation and amortization
5,571

 
15,796

 
16,984

 
38,351

Operating gross margin excluding depreciation and amortization
$
(1,981
)
 
$
22,640

 
$
21,713

 
$
42,372

(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 June 30, 2016 and 2015, respectively:
 
Three Months Ended June 30,
 
2016
 
2015
U.S. (Lower 48) Drilling
 
 
 
Rigs available for service (1)
13.0

 
13.0

Utilization rate of rigs available for service (2)
5
%
 
14
%
International & Alaska Drilling
 
 
 
Eastern Hemisphere
 
 
 
Rigs available for service (1)
13.0

 
13.0

Utilization rate of rigs available for service (2)
38
%
 
69
%
Latin America Region
 
 
 
Rigs available for service (1)
7.0

 
9.0

Utilization rate of rigs available for service (2)
29
%
 
41
%
Alaska
 
 
 
Rigs available for service (1)
2.0

 
2.0

Utilization rate of rigs available for service (2)
100
%
 
100
%
Total International & Alaska Drilling
 
 
 
Rigs available for service (1)
22.0

 
24.0

Utilization rate of rigs available for service (2)
41
%
 
61
%
(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.


34


Drilling Services Business Line
U.S. (Lower 48) Drilling
U.S. (Lower 48) Drilling segment revenues decreased $5.7 million, or 83.8 percent, to $1.1 million for the second quarter of 2016 compared with revenues of $6.8 million for the second quarter of 2015. The decrease was primarily due to lower utilization driven by substantial reductions in drilling activity by operators in the inland waters of the Gulf of Mexico (GOM) resulting from lower oil prices. Utilization declined to 5.0 percent for the quarter ended June 30, 2016 from 14.0 percent for the quarter ended June 30, 2015, resulting in a $2.8 million decrease in revenue. The remainder of the decrease in revenue was primarily driven by a decrease of $2.5 million from our O&M contract supporting three platform operations located offshore California, as the O&M contract ended during the 2015 fourth quarter.
U.S. (Lower 48) Drilling segment operating gross margin excluding depreciation and amortization decreased $1.9 million to a loss of $3.9 million for the second quarter of 2016 compared to a loss of $2.0 million for the second quarter of 2015. The decrease was primarily due to the decline in utilization and the ending of the O&M contract discussed above.
International & Alaska Drilling
International & Alaska Drilling segment revenues decreased $43.1 million, or 37.5 percent, to $71.9 million for the second quarter of 2016 compared with $115.0 million for the second quarter of 2015.
The decrease in revenues was primarily due to the following:
•
a decrease of $13.2 million resulting from decreased utilization for Company-owned rigs driven by the decline in oil prices resulting in reduced customer activity. Utilization for the segment decreased to 41.0 percent for the quarter ended June 30, 2016 from 61.0 percent for the quarter ended June 30, 2015;
•
a decrease of $14.0 million driven by a decline in revenues per day resulting from certain Company-owned and customer-owned rigs shifting to standby mode during the second quarter of 2016 compared to operating mode during the second quarter of 2015, as well as a reduction in average dayrates due to pricing pressures from customers resulting from the decline in oil prices; and
•
a decrease in reimbursable revenues of $10.1 million, which decreased revenues but had a minimal impact on operating margins.
International & Alaska Drilling segment operating gross margin excluding depreciation and amortization decreased $4.8 million, or 21.2 percent, to $17.8 million for the second quarter of 2016 compared with $22.6 million for the second quarter of 2015. The decrease in operating gross margin excluding depreciation and amortization was primarily due to the impact of reduced utilization and reduced revenues discussed above.
Rental Tools Services Business Line
Rental Tools segment revenues decreased $31.8 million, or 49.6 percent, to $32.3 million for the second quarter of 2016 compared with $64.1 million for the second quarter of 2015. The decrease was due to a $17.4 million decrease in our U.S. revenues and a $14.4 million decrease in our international revenues. The decreases were primarily attributable to the continued reduction in customer activity and pricing pressures resulting from lower oil prices.
Rental Tools segment operating gross margin excluding depreciation and amortization decreased $19.5 million, or 89.9 percent, to $2.2 million in the second quarter of 2016 compared with $21.7 million for the second quarter of 2015. The decrease in operating gross margin excluding depreciation and amortization primarily consists of a $9.8 million decrease for our U.S. operations and a $9.7 million decrease for our international operations. In both cases the decrease was due to the declines in oil prices and customer activity discussed above, partially offset by lower operating costs resulting from cost reduction efforts.
Other Financial Data
General and administrative expense
General and administration expense decreased $1.5 million to $8.0 million for the second quarter of 2016, compared with $9.5 million for the second quarter of 2015 primarily due to reduced personnel costs resulting from cost savings initiatives.

35


Provision for reduction in carrying value of certain assets
There was no provision for reduction in carrying value of certain assets recorded during the second quarter of 2016 compared to a $2.3 million provision for reduction in carrying value recorded during the second quarter of 2015 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.
Gain/loss on disposition of assets
Net losses recognized on asset dispositions were nominal for the second quarters of 2016 and 2015, respectively. Activity in both periods included the results of asset sales. We periodically sell equipment deemed to be excess, obsolete, or not currently required for operations.
Interest income and expense
Interest expense increased $0.8 million to $12.2 million for the second quarter of 2016 compared with $11.4 million for the second quarter of 2015. The increase in interest expense was primarily related to write off of $1.1 million of debt issuance costs during the second quarter of 2016 in conjunction with the execution of the Third Amendment to the 2015 Secured Credit Agreement on May 27, 2016, which resulted in the reduction of our Revolver by 50 percent. This increase was partially offset by $0.3 million of accretion of contingent consideration recorded in the second quarter of 2015 that did not recur in the second quarter of 2016, as the contingent consideration had been fully paid as of April 2016. Interest income during each of the 2016 and 2015 second quarters was nominal.
Other income and expense
Other expense was $0.4 million and $1.5 million for the second quarters of 2016 and 2015, respectively. Other expense for the second quarters of 2016 and 2015 included the impact of foreign currency fluctuations. Other expense for the second quarter of 2015 also included a loss on divestiture of our controlling interest in a consolidated joint venture.
Income tax expense (benefit)
During the second quarter of 2016 we had income tax benefit of $0.9 million compared to a tax benefit of $6.9 million during the second quarter of 2015. The income tax benefit in the second quarter of 2016 was primarily related to the jurisdictional mix of income and loss during the quarter along with our continued inability to recognize the benefits associated with certain losses as a result of valuation allowances. The income tax benefit in the second quarter of 2015 was primarily related to pre-tax losses generated during that period.

36


Six Months Ended June 30, 2016 Compared with Six Months Ended June 30, 2015
Revenues decreased $154.2 million, or 39.5 percent, to $235.8 million for the six months ended June 30, 2016 as compared to revenues of $390.0 million for the six months ended June 30, 2015. Operating gross margin decreased $62.0 million, or 219.1 percent, to a loss of $33.7 million for the six months ended June 30, 2016 as compared to income of $28.3 million for the six months ended June 30, 2015.
    The following is an analysis of our operating results for the comparable periods by reportable segment:
 
Six Months Ended June 30,
Dollars in Thousands
2016
 
2015
Revenues:
 
Drilling Services:
 
 
 
 
 
 
 
U.S. (Lower 48) Drilling
$
3,150

 
1
%
 
$
20,945

 
5
%
International & Alaska Drilling
160,545

 
68
%
 
228,890

 
59
%
Total Drilling Services
163,695

 
69
%
 
249,835

 
64
%
Rental Tools
72,095

 
31
%
 
140,182

 
36
%
Total revenues
235,790

 
100
%
 
390,017

 
100
%
Operating gross margin (loss) excluding depreciation and amortization:
 
 
 
 
 
 
 
Drilling Services:
 
 
 
 
 
 
 
U.S. (Lower 48) Drilling
(7,239
)
 
n/m

 
(1,866
)
 
n/m

International & Alaska Drilling
36,710

 
23
%
 
58,032

 
25
%
Total Drilling Services
29,471

 
18
%
 
56,166

 
23
%
Rental Tools
9,007

 
12
%
 
51,012

 
36
%
Total operating gross margin excluding depreciation and amortization
38,478

 
16
%
 
107,178

 
28
%
Depreciation and amortization
(72,131
)
 
 
 
(78,890
)
 
 
Total operating gross margin
(33,653
)
 
 
 
28,288

 
 
General and administrative expense
(17,776
)
 
 
 
(20,348
)
 
 
Provision for reduction in carrying value of certain assets
—

 
 
 
(2,316
)
 
 
Gain (loss) on disposition of assets, net
(62
)
 
 
 
2,303

 
 
Total operating income (loss)
$
(51,491
)
 
 
 
$
7,927

 
 

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
Six Months Ended June 30, 2016
 
 
 
 
 
 
 
Operating gross margin (1)
$
(17,571
)
 
$
8,274

 
$
(24,356
)
 
$
(33,653
)
Depreciation and amortization
10,332

 
28,436

 
33,363

 
72,131

Operating gross margin excluding depreciation and amortization
$
(7,239
)
 
$
36,710

 
$
9,007

 
$
38,478

Six Months Ended June 30, 2015
 
 
 
 
 
 
 
Operating gross margin (1)
$
(13,274
)
 
$
24,208

 
$
17,354

 
$
28,288

Depreciation and amortization
11,408

 
33,824

 
33,658

 
78,890

Operating gross margin excluding depreciation and amortization
$
(1,866
)
 
$
58,032

 
$
51,012

 
$
107,178

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

37


The following table presents our average utilization rates and rigs available for service for the six months ended June 30, 2016 and 2015, respectively:
 
Six Months Ended June 30,
 
2016
 
2015
U.S. (Lower 48) Drilling
 
 
 
Rigs available for service (1)
13.0

 
13.0

Utilization rate of rigs available for service (2)
6
%
 
17
%
International & Alaska Drilling
 
 
 
Eastern Hemisphere
 
 
 
Rigs available for service (1)
13.0

 
13.0

Utilization rate of rigs available for service (2)
43
%
 
76
%
Latin America Region
 
 
 
Rigs available for service (1)
7.0

 
9.0

Utilization rate of rigs available for service (2)
29
%
 
43
%
Alaska
 
 
 
Rigs available for service (1)
2.0

 
2.0

Utilization rate of rigs available for service (2)
100
%
 
100
%
Total International & Alaska Drilling
 
 
 
Rigs available for service (1)
22.0

 
24.0

Utilization rate of rigs available for service (2)
44
%
 
66
%
(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 $17.7 million, or 84.7 percent, to $3.2 million for the six months ended June 30, 2016 compared with revenues of $20.9 million for the six months ended June 30, 2015. The decrease was primarily due to lower utilization driven by substantial reductions in drilling activity by operators in the inland waters of the GOM resulting from lower oil prices. Utilization declined to 6.0 percent for the six months ended June 30, 2016 from 17.0 percent for the six months ended June 30, 2015, resulting in a $9.0 million decrease in revenue. The remainder of the decrease in revenues was primarily driven by a decrease of $6.7 million from our O&M contract supporting three platform operations located offshore California, as the O&M contract ended during the 2015 fourth quarter.
U.S. (Lower 48) Drilling segment operating gross margin excluding depreciation and amortization decreased $5.3 million to a loss of $7.2 million for the six months ended June 30, 2016 compared with a loss of $1.9 million for the six months ended June 30, 2015. The decrease was primarily due to the decline in utilization and the ending of the O&M contract discussed above.
International & Alaska Drilling
International & Alaska Drilling segment revenues decreased $68.4 million, or 29.9 percent, to $160.5 million for the six months ended June 30, 2016 compared with $228.9 million for the six months ended June 30, 2015.
The decrease in revenues was primarily due to the following:

38


•
a decrease of $31.8 resulting from decreased utilization for Company-owned rigs driven by the decline in oil prices resulting in reduced customer activity. Utilization for the segment decreased to 44.0 percent for the six months ended June 30, 2016 from 66.0 percent for the six months ended June 30, 2015;
•
a decrease of $19.9 million driven by a decline in revenues per day resulting from certain Company-owned and customer-owned rigs shifting to standby mode during the second quarter of 2016 compared to operating mode during the second quarter of 2015, as well as a reduction in average dayrates due to pricing pressures from customers resulting from the decline in oil prices;
•
a decrease in reimbursable revenues of $10.1 million, which decreased revenues but had a minimal impact on operating margins; and
•
a decrease of $8.9 million of revenues earned from mobilization and demobilization activities.
The decrease in revenues was partially offset by an increase of $5.1 million of revenues generated from our project service activities.
International & Alaska Drilling segment operating gross margin excluding depreciation and amortization decreased $21.3 million, or 36.7 percent, to $36.7 million for the six months ended June 30, 2016 compared with $58.0 million for the six months ended June 30, 2015. The decrease in operating gross margin excluding depreciation and amortization was primarily due to the impact of reduced utilization and revenues discussed above.
Rental Tools Services Business Line
Rental Tools segment revenues decreased $68.1 million, or 48.6 percent, to $72.1 million for the six months ended June 30, 2016 compared with $140.2 million for the six months ended June 30, 2015. The decrease was due to a $40.7 million decrease in our U.S. revenues and a $27.4 million decrease in our international revenues. The decreases were primarily attributable to the continued reduction in customer activity and pricing pressures resulting from lower oil prices.
Rental Tools segment operating gross margin excluding depreciation and amortization decreased $42.0 million, or 82.4 percent, to $9.0 million in the six months ended June 30, 2016 compared with $51.0 million for the six months ended June 30, 2015. The decrease in operating gross margin excluding depreciation and amortization primarily consists of a $23.6 million decrease for our U.S. operations and an $18.4 million decrease for our international operations. In both cases the decrease was due to the declines in oil prices and customer activity discussed above, partially offset by lower operating costs resulting from cost reduction efforts.
Other Financial Data
General and administrative expense
General and administration expense decreased $2.5 million to $17.8 million for the six months ended June 30, 2016, compared with $20.3 million for the six months ended June 30, 2015. General and administrative expense for the six months ended June 30, 2016 benefited from cost savings initiatives, while general and administrative expense for the six months ended June 30, 2015 was higher primarily due to increased expenses as we implemented the second phase of our new enterprise resource planning system.
Provision for reduction in carrying value of certain assets
There was no provision for reduction in carrying value of certain assets recorded during the six months ended June 30, 2016 compared to a $2.3 million provision for reduction in carrying value recorded during the six months ended June 30, 2015 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.
Gain/loss on disposition of assets
Net losses recognized on asset dispositions were $0.1 million during the six months ended June 30, 2016, compared with net gains of $2.3 million during the six months ended June 30, 2015. Activity in both periods included the result of asset sales; however, the net gains for the six months ended June 30, 2015 were primarily due to an insurance settlement received during the quarter related to previously realized asset losses. Additionally, we periodically sell equipment deemed to be excess, obsolete, or not currently required for operations.

39


Interest income and expense
Interest expense increased $1.2 million to $23.7 million for the six months ended June 30, 2016 compared with $22.5 million for the six months ended June 30, 2015. The increase in interest expense was primarily related to write off of $1.1 million of debt issuance costs during the second quarter of 2016 in conjunction with the execution of the Third Amendment to the 2015 Secured Credit Agreement on May 27, 2016, which resulted in the reduction of our Revolver by 50 percent. Interest income during each of the six months ended June 30, 2016 and 2015 was nominal.
Other income and expense
Other income for the six months ended June 30, 2016 was $2.1 million compared with other expense for the six months ended June 30, 2015 of $2.9 million. Other income for the six months ended June 30, 2016 was primarily attributable to a reclassification of $1.9 million of realized foreign currency translation gains from accumulated other comprehensive income and the settlement of certain legal claims, resulting in other income of $0.6 million. Other expense for the six months ended June 30, 2015 was primarily driven by losses related to foreign currency fluctuations and a loss on divestiture of our controlling interest in a consolidated joint venture.
Income tax expense (benefit)
During the six months ended June 30, 2016 we had income tax expense of $62.6 million compared to a tax benefit of $7.1 million during the six months ended June 30, 2015.  Despite the pre-tax operating loss for the six months ended June 30, 2016, we recognized income tax expense as a result of recording a valuation allowance in the first quarter of $73.1 million against our U.S. domestic deferred tax assets, which primarily consist of U.S. federal net operating losses.  We established the valuation allowance based on the weight of positive and negative evidence available, including the recent and current results of operations which reflect continued degradation in market activity and including the increased contractual uncertainty materializing during the period in the U.S. jurisdictions in which we operate. In order to determine the need for a valuation allowance, we must make estimates and assumptions regarding events occurring during the six months ended June 30, 2016.  Changes in these estimates and assumptions, including changes in tax laws and other changes impacting our ability to recognize the underlying deferred tax assets, may require us to adjust the valuation allowances in the future. The income tax benefit in the six months ended June 30, 2015 was primarily related to pre-tax losses generated during that period.
Backlog
Backlog is our estimate of the dollar amount of revenues we expect to realize in the future as a result of executing awarded contracts. The Company’s backlog of firm orders was approximately $446 million at June 30, 2016 and $438 million at June 30, 2015 and is primarily attributable to the International & Alaska segment of our Drilling Services business. We estimate that, as of June 30, 2016, 18 percent of our backlog will be recognized as revenues within the fiscal year.
The amount of actual revenues earned and the actual periods during which revenues are earned could be different from amounts disclosed in our backlog calculations due to a lack of predictability of various factors, including unscheduled repairs, maintenance requirements, weather delays, contract terminations or renegotiations, new contracts and other factors. See “Our backlog of contracted revenue may not be fully realized and may reduce significantly in the future, which may have a material adverse effect on our financial position, results of operations or cash flows” in Item 1A. Risk Factors of our 2015 Form 10-K. 

40


LIQUIDITY AND CAPITAL RESOURCES
We periodically evaluate our liquidity requirements, capital needs and availability of resources in view of expansion plans, debt service requirements, and other operational cash needs. To meet our short- and long-term liquidity requirements, including payment of operating expenses and repaying debt, we rely primarily on cash from operations. We also have access to cash through the Revolver, subject to our compliance with the covenants contained in the 2015 Secured Credit Agreement. We expect that these sources of liquidity will be sufficient to provide us the ability to fund our operations, provide the working capital necessary to support our strategy, and fund planned capital expenditures. When determined appropriate we may seek to raise additional capital in the future. We do not pay dividends to our shareholders.
Liquidity
The following table provides a summary of our total liquidity:
 
June 30, 2016
Dollars in thousands
 
Cash and cash equivalents on hand (1)
$
109,034

Availability under Revolver (2)
88,187

Total liquidity
$
197,221

(1) As of June 30, 2016, approximately $41.7 million of the $109.0 million of cash and equivalents was held by our foreign subsidiaries.
(2) Availability under the Revolver included $100 million undrawn portion of our Revolver less $11.8 million of letters of credit outstanding. In order to access the 2015 Revolver, we must be in compliance with the covenants contained in the 2015 Secured Credit Agreement.
The earnings of foreign subsidiaries as of June 30, 2016 were reinvested to fund our international operations.  If in the future we decide to repatriate earnings to the United States, the Company may be required to pay taxes on these amounts based on applicable United States tax law, which would reduce the liquidity of the Company at that time.
We do not have any unconsolidated special-purpose entities, off-balance sheet financing arrangements or guarantees of third-party financial obligations. As of June 30, 2016, we have no energy, commodity, or foreign currency derivative contracts.
Cash Flow Activity
As of June 30, 2016, we had cash and cash equivalents of $109.0 million, a decrease of $25.3 million from cash and cash equivalents of $134.3 million at December 31, 2015. The following table provides a summary of our cash flow activity:
 
Six Months Ended June 30, 2016
Dollars in thousands
2016
 
2015
Operating Activities
$
602

 
$
103,093

Investing Activities
(14,870
)
 
(62,248
)
Financing Activities
(10,992
)
 
(32,358
)
Net change in cash and cash equivalents
$
(25,260
)
 
$
8,487

Operating Activities
Cash flows from operating activities were a source of $0.6 million for the six months ended June 30, 2016 compared to a source of $103.1 million for the six months ended June 30, 2015. Cash flows from operating activities in each period were largely impacted by our earnings and changes in working capital. Changes in working capital were a source of cash of $8.5 million for the six months ended June 30, 2016 compared to a source of cash of $45.9 million for the six months ended June 30, 2015. In addition to the impact of earnings and working capital changes cash flows from operating activities in each period were impacted by non-cash charges such as depreciation expense, gains on asset sales, deferred tax benefit, stock compensation expense, debt modification and amortization of debt issuance costs.
Over the past few years we have reinvested a substantial portion of our operating cash flows to enhance our fleet of drilling rigs and our rental tools equipment inventory. It is our long term intention to utilize our operating cash flows to fund

41


maintenance and growth of our rental tool assets and drilling rigs; however, given the decline in demand in the current oil and natural gas services market, our short-term focus is to preserve liquidity by managing our costs and capital expenditures.
Investing Activities
Cash flows from investing activities were a use of $14.9 million for the six months ended June 30, 2016 compared with a use of $62.2 million for the six months ended June 30, 2015. Our primary use of cash during the six months ended June 30, 2016 and 2015 was $16.3 million and $54.6 million, respectively, for capital expenditures. Capital expenditures in each period were primarily for tubular and other products for our Rental Tools Services business and rig-related maintenance. During the six months ended June 30, 2015 we had a use of cash of $10.4 million, net of cash acquired, in connection with the 2M-Tek Acquisition.
Financing Activities
Cash flows from financing activities were a use of $11.0 million for the six months ended June 30, 2016, primarily due to the payment of $6.0 million of the contingent consideration related to the 2M-Tek Acquisition. The payment was made upon the achievement of certain milestones during the first and second quarters of 2016. In addition, during the six months ended June 30, 2016, we had a use of cash of $3.4 million in connection with the final payment of the purchase price for the remaining noncontrolling interest of ITS Arabia Limited. Cash flows from financing activities were a use of $32.4 million for the 2015 comparable period, primarily driven by the repayment of the $30.0 million balance on a term loan in the first quarter of 2015.
Long-Term Debt Summary
Our principal amount of long-term debt, including current portion, was $575.5 million as of June 30, 2016 which consisted of:
•$360.0 million aggregate principal amount of 6.75% Notes; and
•$225.0 million aggregate principal amount of 7.50% Notes; less
•$9.5 million of unamortized debt issuance costs
6.75% Senior Notes, due July 2022
On January 22, 2014, we issued $360.0 million aggregate principal amount of 6.75% Senior Notes due 2022 (6.75% Notes) pursuant to an Indenture between the Company and The Bank of New York Mellon Trust Company, N.A., as trustee. Net proceeds from the 6.75% Notes offering plus a $40.0 million term loan draw under the Amended and Restated Senior Secured Credit Agreement (2012 Secured Credit Agreement) and cash on hand were utilized to purchase $416.2 million aggregate principal amount of our outstanding 9.125% Senior Notes due 2018 pursuant to a tender and consent solicitation offer commenced on January 7, 2014.
The 6.75% Notes are general unsecured obligations of the Company and rank equal in right of payment with all of our existing and future senior unsecured indebtedness. The 6.75% Notes are jointly and severally guaranteed by all of our subsidiaries that guarantee indebtedness under the Second Amended and Restated Senior Secured Credit Agreement, as amended from time-to-time (2015 Secured Credit Agreement) and our 7.50% Senior Notes due 2020 (7.50% Notes, and collectively with the 6.75% Notes, the Senior Notes). Interest on the 6.75% Notes is payable on January 15 and July 15 of each year, beginning July 15, 2014. Debt issuance costs related to the 6.75% Notes of approximately $7.6 million ($5.9 million net of amortization as of June 30, 2016) are being amortized over the term of the notes using the effective interest rate method.
At any time prior to January 15, 2017, we may redeem up to 35 percent of the aggregate principal amount of the 6.75% Notes at a redemption price of 106.75 percent of the principal amount, plus accrued and unpaid interest to the redemption date, with the net cash proceeds of certain equity offerings by us. 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.

42


7.50% Senior Notes, due August 2020
On July 30, 2013, we issued $225.0 million aggregate principal amount of the 7.50% Notes pursuant to an Indenture between the Company and The Bank of New York Mellon Trust Company, N.A., as trustee. Net proceeds from the 7.50% Notes offering were primarily used to repay the $125.0 million aggregate principal amount of a term loan used to initially finance the ITS Acquisition, to repay $45.0 million of term loan borrowings under the 2012 Secured Credit Agreement, and for general corporate purposes.
The 7.50% Notes are general unsecured obligations of the Company and rank equal in right of payment with all of our existing and future senior unsecured indebtedness. The 7.50% Notes are jointly and severally guaranteed by all of our subsidiaries that guarantee indebtedness under the 2015 Secured Credit Agreement and the 6.75% Notes. Interest on the 7.50% Notes is payable on February 1 and August 1 of each year, beginning February 1, 2014. Debt issuance costs related to the 7.50% Notes of approximately $5.6 million ($3.6 million, net of amortization as of June 30, 2016) are being amortized over the term of the notes using the effective interest rate method.
At any time prior to August 1, 2016, we were entitled to 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. To date we have not made any redemptions. If we experience certain changes in control, we must offer to repurchase the 7.50% Notes at 101.0 percent of the aggregate principal amount, plus accrued and unpaid interest and additional interest, if any, to the date of repurchase.
The Indenture restricts our ability and the ability of certain subsidiaries to: (i) sell assets, (ii) pay dividends or make other distributions on capital stock or redeem or repurchase capital stock or subordinated indebtedness, (iii) make investments, (iv) incur or guarantee additional indebtedness, (v) create or incur liens, (vi) enter into sale and leaseback transactions, (vii) incur dividend or other payment restrictions affecting subsidiaries, (viii) merge or consolidate with other entities, (ix) enter into transactions with affiliates, and (x) engage in certain business activities. Additionally, the Indenture contains certain restrictive covenants designating certain events as Events of Default. These covenants are subject to a number of important exceptions and qualifications.
2015 Secured Credit Agreement
On January 26, 2015 we entered into the 2015 Secured Credit Agreement, which amended and restated the 2012 Secured Credit Agreement. The 2015 Secured Credit Agreement was originally comprised of a $200.0 million revolving credit facility (Revolver) set to mature on January 26, 2020. On June 1, 2015, we executed the first amendment to the 2015 Secured Credit Agreement in order to amend certain provisions regarding the definition of “Change of Control.” On September 29, 2015, we executed the second amendment to the 2015 Secured Credit Agreement to, among other things, (a) amend certain covenant ratios; (b) increase the Applicable Rate for certain higher levels of consolidated leverage to a maximum of 4.00 percent per annum for Eurodollar Rate loans and to 3.00 percent per annum for Base Rate loans; (c) permit multi-year letters of credit up to an aggregate amount of $5.0 million; (d) limit payment prior to September 30, 2017 of certain restricted payments and certain prepayments of unsecured senior notes and other specified forms of indebtedness; and (e) remove the option of the Company, subject to the consent of the lenders, to increase the Credit Agreement up to an additional $75 million. On May 27, 2016, we executed the third amendment to the 2015 Secured Credit Agreement (the Third Amendment), which reduced availability under the Revolver from $200 million to $100 million. Additionally, among other things, the Third Amendment: (a) eliminates the Leverage Ratio covenant until the fourth quarter of 2018 when the covenant is reinstated with the ratio established at 4.25:1.00, and remains at 4.25:1.00 thereafter; (b) eliminates the Consolidated Interest Coverage Ratio covenant until the fourth quarter of 2017 when the covenant is reinstated with the ratio established at 1.00:1.00 and increases by 0.25 each subsequent quarter until reaching 2.00:1.00 in the fourth quarter of 2018, and remains at 2.00:1.00 thereafter; (c) immediately increases the maximum permitted Senior Secured Leverage Ratio from 1.50:1.00 to 2.80:1.00 until it decreases to 2.20:1.00 in the second quarter of 2017, to 1.75:1.00 in the third quarter of 2017, and to 1.50:1.00 in the fourth quarter of 2017 and remains at 1.50:1.00 thereafter; (d) immediately decreases the minimum permitted Asset Coverage Ratio from 1.25:1.00 to 1.10:1.00 until it increases to 1.25: 1.00 in the fourth quarter of 2017 and remains at 1.25:1.00 thereafter; (e) requires that, at any time our Consolidated Cash Balance in U.S. bank accounts is over $50 million, we repay borrowings under the 2015 Secured Credit Agreement until our Consolidated Cash balance is no more than $50 million or all borrowings have been repaid, and (f) allows up to $75 million of Junior Lien Debt.
At the time the Third Amendment was executed, the remaining debt issuance costs for the 2015 Secured Credit Agreement totaled approximately $2.2 million. Since the Revolver was reduced by 50 percent, we wrote off approximately $1.1 million in May 2016. We incurred debt issuance costs relating to the Third Amendment of approximately $0.3 million, bringing total debt issuance costs to $1.4 million ($1.3 million, net of amortization as of June 30, 2016) which are being amortized through January 2020, or the term of the Third Amendment, on a straight line basis.

43


Our obligations under the 2015 Secured Credit Agreement are guaranteed by substantially all of our direct and indirect domestic subsidiaries, other than immaterial subsidiaries and subsidiaries generating revenues primarily outside the United States, each of which has executed guaranty agreements, and are secured by first priority liens on our accounts receivable, specified rigs including barge rigs in the GOM and land rigs in Alaska, certain U.S.-based rental equipment of the Company and its subsidiary guarantors and the equity interests of certain of the Company’s subsidiaries. The 2015 Secured Credit Agreement contains customary affirmative and negative covenants, such as limitations on indebtedness, liens, restrictions on entry into certain affiliate transactions and payments (including payment of dividends) and maintenance of certain ratios and coverage tests. We were in compliance with all covenants contained in the 2015 Secured Credit Agreement as of June 30, 2016.
Our Revolver is available for general corporate purposes and to support letters of credit. Interest on Revolver loans accrues at a Base Rate plus an Applicable Rate or LIBOR plus an Applicable Rate. Revolving loans are available subject to a quarterly asset coverage ratio calculation based on the Orderly Liquidation Value of certain specified rigs including barge rigs in the GOM and land rigs in Alaska, and certain U.S.-based rental equipment of the Company and its subsidiary guarantors and a percentage of eligible domestic accounts receivable. The $30.0 million draw outstanding at the closing of the 2015 Secured Credit Agreement was repaid in full during the first quarter of 2015 with cash on hand. Letters of credit outstanding against the Revolver as of June 30, 2016 totaled $11.8 million. There were no amounts drawn on the Revolver as of June 30, 2016.
Item 3. Quantitative and Qualitative Disclosures about Market Risk
There has been no material change in the market risk faced by us from that reported in our 2015 Form 10-K. For more information on market risk, see Part II, Item 7A in our 2015 Form 10-K.
Item 4. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
In accordance with Rules 13a-15 and 15d-15 under the Exchange Act, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective, as of June 30, 2016, to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and accumulated and communicated to our management, including our Chief Executive Officer and our Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.
Changes in Internal Controls Over Financial Reporting
There have been no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during our most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.



44


PART II. OTHER INFORMATION 
Item 1. Legal Proceedings
For information regarding legal proceedings, see Note 11, “Commitments and Contingencies,” in Item 1 of Part I of this quarterly report on Form 10-Q, which information is incorporated into this item by reference. 
Item 1A. Risk Factors
There have been no material changes from the risk factors disclosed in Item 1A. Risk Factors of our 2015 Form 10-K. 
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
The Company currently has no active share repurchase programs.
Item 3. Defaults Upon Senior Securities
None.
Item 4. Mine Safety Disclosures
None.
Item 5. Other Information
None.

45


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
 
—
 
Third Amendment to the Second Amended and Restated Credit Agreement, dated May 27, 2016, 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.



46


SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
 
 
 
 
 
 
 
 
PARKER DRILLING COMPANY
 
 
 
 
 
Date:
August 3, 2016
By:
 
/s/ Gary G. Rich
 
 
 
 
Gary G. Rich
Chairman, President and Chief Executive Officer
 
 
 
 
 
 
 
By:
 
/s/ Christopher T. Weber
 
 
 
 
Christopher T. Weber
Senior Vice President and Chief Financial Officer


47


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
 
—
 
Third Amendment to the Second Amended and Restated Credit Agreement, dated May 27, 2016, 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.


48