Document
Table of Contents

 
 
 
 
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
FORM 10-Q
 
ý
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2017
or
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                  to                 
Commission file number: 1-34776

Oasis Petroleum Inc.
(Exact name of registrant as specified in its charter)
 
 
 
 
Delaware
 
80-0554627
(State or other jurisdiction of
incorporation or organization)
 
(I.R.S. Employer
Identification No.)
 
 
1001 Fannin Street, Suite 1500
Houston, Texas
 
77002
(Address of principal executive offices)
 
(Zip Code)

(281) 404-9500
(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  ý   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 ý  No ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer”, “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act. 
Large accelerated filer
ý
Accelerated filer
¨
 
 
 
 
Non-accelerated filer
o  (Do not check if a smaller reporting company)
Smaller reporting company
¨
 
 
 
 
 
 
Emerging growth company
¨
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.  ¨ 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes ¨ No ý
Number of shares of the registrant’s common stock outstanding at July 31, 2017: 237,415,441 shares.
 
 
 
 
 


Table of Contents

OASIS PETROLEUM INC.
FORM 10-Q
FOR THE QUARTER ENDED JUNE 30, 2017
TABLE OF CONTENTS
 
 
Page

Table of Contents

PART I — FINANCIAL INFORMATION
Item 1. — Financial Statements (Unaudited)
Oasis Petroleum Inc.
Condensed Consolidated Balance Sheets
(Unaudited)
 
June 30, 2017
 
December 31, 2016
 
(In thousands, except share data)
ASSETS
 
 
 
Current assets
 
 
 
Cash and cash equivalents
$
11,440

 
$
11,226

Accounts receivable, net
218,302

 
204,335

Inventory
17,942

 
10,648

Prepaid expenses
10,610

 
7,623

Derivative instruments
31,851

 
362

Other current assets
62

 
4,355

Total current assets
290,207

 
238,549

Property, plant and equipment
 
 
 
Oil and gas properties (successful efforts method)
7,488,075

 
7,296,568

Other property and equipment
695,592

 
618,790

Less: accumulated depreciation, depletion, amortization and impairment
(2,252,653
)
 
(1,995,791
)
Total property, plant and equipment, net
5,931,014

 
5,919,567

Derivative instruments
11,834

 
—

Long-term inventory
8,762

 
—

Other assets
19,904

 
20,516

Total assets
$
6,261,721

 
$
6,178,632

LIABILITIES AND STOCKHOLDERS’ EQUITY
 
 
 
Current liabilities
 
 
 
Accounts payable
$
12,257

 
$
4,645

Revenues and production taxes payable
143,715

 
139,737

Accrued liabilities
139,766

 
119,173

Accrued interest payable
39,128

 
39,004

Derivative instruments
—

 
60,469

Advances from joint interest partners
5,816

 
7,597

Other current liabilities
—

 
10,490

Total current liabilities
340,682

 
381,115

Long-term debt
2,359,683

 
2,297,214

Deferred income taxes
527,181

 
513,529

Asset retirement obligations
51,059

 
48,985

Derivative instruments
—

 
11,714

Other liabilities
5,506

 
2,918

Total liabilities
3,284,111

 
3,255,475

Commitments and contingencies (Note 13)

 

Stockholders’ equity
 
 
 
Common stock, $0.01 par value: 450,000,000 shares authorized; 238,642,598 shares issued and 237,410,395 shares outstanding at June 30, 2017 and 237,201,064 shares issued and 236,344,172 shares outstanding at December 31, 2016
2,345

 
2,331

Treasury stock, at cost: 1,232,203 and 856,892 shares at June 30, 2017 and December 31, 2016, respectively
(21,401
)
 
(15,950
)
Additional paid-in capital
2,362,084

 
2,345,271

Retained earnings
634,582

 
591,505

Total stockholders’ equity
2,977,610

 
2,923,157

Total liabilities and stockholders’ equity
$
6,261,721

 
$
6,178,632


The accompanying notes are an integral part of these condensed consolidated financial statements.

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Oasis Petroleum Inc.
Condensed Consolidated Statements of Operations
(Unaudited)
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2017
 
2016
 
2017
 
2016
 
(In thousands, except per share data)
Revenues
 
 
 
 
 
 
 
Oil and gas revenues
$
218,633

 
$
159,337

 
$
455,885

 
$
276,652

Bulk oil sales
8,091

 
—

 
35,722

 
—

Midstream revenues
15,566

 
6,910

 
30,172

 
13,893

Well services revenues
11,801

 
12,833

 
17,428

 
18,818

Total revenues
254,091

 
179,080

 
539,207

 
309,363

Operating expenses
 
 
 
 
 
 
 
Lease operating expenses
44,665

 
31,523

 
88,537

 
62,587

Midstream operating expenses
3,263

 
1,740

 
6,590

 
3,478

Well services operating expenses
8,088

 
7,135

 
11,990

 
9,786

Marketing, transportation and gathering expenses
12,039

 
6,491

 
22,990

 
15,043

Bulk oil purchases
7,980

 
—

 
35,982

 
—

Production taxes
18,971

 
14,367

 
39,270

 
25,120

Depreciation, depletion and amortization
125,291

 
122,488

 
251,957

 
244,937

Exploration expenses
1,667

 
340

 
3,156

 
703

Impairment
3,200

 
23

 
5,882

 
3,585

General and administrative expenses
23,548

 
21,876

 
47,382

 
46,242

Total operating expenses
248,712

 
205,983

 
513,736

 
411,481

Loss on sale of properties
—

 
(1,311
)
 
—

 
(1,311
)
Operating income (loss)
5,379

 
(28,214
)
 
25,471

 
(103,429
)
Other income (expense)
 
 
 
 
 
 
 
Net gain (loss) on derivative instruments
50,532

 
(90,846
)
 
106,607

 
(76,471
)
Interest expense, net of capitalized interest
(36,838
)
 
(34,979
)
 
(73,159
)
 
(73,718
)
Gain on extinguishment of debt
—

 
11,642

 
—

 
18,658

Other income (expense)
(166
)
 
(32
)
 
(150
)
 
447

Total other income (expense)
13,528

 
(114,215
)
 
33,298

 
(131,084
)
Income (loss) before income taxes
18,907

 
(142,429
)
 
58,769

 
(234,513
)
Income tax benefit (expense)
(2,339
)
 
52,498

 
(18,376
)
 
80,127

Net income (loss)
$
16,568

 
$
(89,931
)
 
$
40,393

 
$
(154,386
)
Earnings (loss) per share:
 
 
 
 
 
 
 
Basic (Note 11)
$
0.07

 
$
(0.51
)
 
$
0.17

 
$
(0.91
)
Diluted (Note 11)
0.07

 
(0.51
)
 
0.17

 
(0.91
)
Weighted average shares outstanding:
 
 
 
 
 
 
 
Basic (Note 11)
233,283

 
176,984

 
233,176

 
169,953

Diluted (Note 11)
234,917

 
176,984

 
236,281

 
169,953


The accompanying notes are an integral part of these condensed consolidated financial statements.


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Oasis Petroleum Inc.
Condensed Consolidated Statement of Changes in Stockholders’ Equity
(Unaudited)
 
Common Stock
 
Treasury Stock
 
Additional
Paid-in Capital
 
Retained Earnings
 
Total
Stockholders’
Equity
Shares
 
Amount
 
Shares
 
Amount
 
 
(In thousands)
Balance at December 31, 2016
236,344

 
$
2,331

 
857

 
$
(15,950
)
 
$
2,345,271

 
$
591,505

 
$
2,923,157

Cumulative-effect adjustment for adoption of ASU 2016-09 (Note 2)
—

 
—

 
—

 
—

 
2,040

 
2,684

 
4,724

Fees (2016 issuance of common stock)
—

 
—

 
—

 
—

 
(55
)
 
—

 
(55
)
Stock-based compensation
1,441

 
14

 
—

 
—

 
14,828

 
—

 
14,842

Treasury stock - tax withholdings
(375
)
 
—

 
375

 
(5,451
)
 
—

 
—

 
(5,451
)
Net income
—

 
—

 
—

 
—

 
—

 
40,393

 
40,393

Balance at June 30, 2017
237,410

 
$
2,345

 
1,232

 
$
(21,401
)
 
$
2,362,084

 
$
634,582

 
$
2,977,610


The accompanying notes are an integral part of these condensed consolidated financial statements.


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Oasis Petroleum Inc.
Condensed Consolidated Statements of Cash Flows
(Unaudited)
 
Six Months Ended June 30,
 
2017
 
2016
 
(In thousands)
Cash flows from operating activities:
 
 
 
Net income (loss)
$
40,393

 
$
(154,386
)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 
 
 
Depreciation, depletion and amortization
251,957

 
244,937

Gain on extinguishment of debt
—

 
(18,658
)
Loss on sale of properties
—

 
1,311

Impairment
5,882

 
3,585

Deferred income taxes
18,376

 
(80,127
)
Derivative instruments
(106,607
)
 
76,471

Stock-based compensation expenses
13,823

 
12,979

Deferred financing costs amortization and other
8,871

 
6,552

Working capital and other changes:
 
 
 
Change in accounts receivable
(13,743
)
 
4,297

Change in inventory
(1,007
)
 
2,054

Change in prepaid expenses
(264
)
 
1,423

Change in other current assets
280

 
(114
)
Change in long-term inventory and other assets
(8,768
)
 
100

Change in accounts payable, interest payable and accrued liabilities
11,158

 
(18,034
)
Change in other current liabilities
(10,490
)
 
9,001

Change in other liabilities
—

 
10

Net cash provided by operating activities
209,861

 
91,401

Cash flows from investing activities:
 
 
 
Capital expenditures
(252,461
)
 
(231,341
)
Proceeds from sale of properties
4,000

 
11,679

Costs related to sale of properties
—

 
(310
)
Derivative settlements
(8,899
)
 
103,790

Advances from joint interest partners
(1,781
)
 
769

Net cash used in investing activities
(259,141
)
 
(115,413
)
Cash flows from financing activities:
 
 
 
Proceeds from revolving credit facility
484,000

 
359,000

Principal payments on revolving credit facility
(429,000
)
 
(462,000
)
Repurchase of senior unsecured notes
—

 
(56,925
)
Deferred financing costs
—

 
(751
)
Proceeds from sale of common stock
—

 
182,953

Purchases of treasury stock
(5,451
)
 
(1,520
)
Other
(55
)
 
—

Net cash provided by financing activities
49,494

 
20,757

Increase (decrease) in cash and cash equivalents
214

 
(3,255
)
Cash and cash equivalents:
 
 
 
Beginning of period
11,226

 
9,730

End of period
$
11,440

 
$
6,475

Supplemental non-cash transactions:
 
 
 
Change in accrued capital expenditures
$
19,017

 
$
(17,015
)
Change in asset retirement obligations
1,759

 
(8,785
)
Notes payable from acquisition
4,875

 
—


The accompanying notes are an integral part of these condensed consolidated financial statements.

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OASIS PETROLEUM INC.
Notes to Condensed Consolidated Financial Statements (Unaudited)
1. Organization and Operations of the Company
Oasis Petroleum Inc. (together with its consolidated subsidiaries, “Oasis” or the “Company”) was originally formed in 2007 and was incorporated pursuant to the laws of the State of Delaware in 2010. The Company is an independent exploration and production company focused on the acquisition and development of unconventional oil and natural gas resources in the North Dakota and Montana regions of the Williston Basin. Oasis Petroleum North America LLC (“OPNA”) conducts the Company’s exploration and production activities and owns its proved and unproved oil and natural gas properties. The Company also operates a midstream services business through Oasis Midstream Services LLC (“OMS”) and a well services business through Oasis Well Services LLC (“OWS”), both of which are separate reportable business segments that are complementary to its primary development and production activities.
2. Summary of Significant Accounting Policies
Basis of Presentation
The accompanying condensed consolidated financial statements of the Company include the accounts of Oasis and its wholly-owned subsidiaries. All significant intercompany transactions have been eliminated in consolidation. The accompanying condensed consolidated financial statements of the Company have not been audited by the Company’s independent registered public accounting firm, except that the Condensed Consolidated Balance Sheet at December 31, 2016 is derived from audited financial statements. Certain reclassifications of prior year balances have been made to conform such amounts to current year classifications. These reclassifications have no impact on net income. In the opinion of management, all adjustments, consisting of normal recurring adjustments necessary for the fair statement, have been included. Management has made certain estimates and assumptions that affect reported amounts in the condensed consolidated financial statements and disclosures of contingencies. Actual results may differ from those estimates. The results for interim periods are not necessarily indicative of annual results.
These interim financial statements have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”) regarding interim financial reporting. Certain disclosures have been condensed or omitted from these financial statements. Accordingly, they do not include all of the information and notes required by accounting principles generally accepted in the United States of America (“GAAP”) for complete consolidated financial statements and should be read in conjunction with the Company’s audited consolidated financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2016 (“2016 Annual Report”).
Risks and Uncertainties
As an oil and natural gas producer, the Company’s revenue, profitability and future growth are substantially dependent upon the prevailing and future prices for oil and natural gas, which are dependent upon numerous factors beyond its control such as economic, political and regulatory developments and competition from other energy sources. The energy markets have historically been very volatile, and there can be no assurance that oil and natural gas prices will not be subject to wide fluctuations in the future. An extended period of low prices for oil and, to a lesser extent, natural gas could have a material adverse effect on the Company’s financial position, results of operations, cash flows and quantities of oil and natural gas reserves that may be economically produced.
Significant Accounting Policies
There have been no material changes to the Company’s critical accounting policies and estimates from those disclosed in the 2016 Annual Report, other than as noted below.
Stock-based compensation. In the first quarter of 2017, the Company adopted Accounting Standards Update No. 2016-09, Improvements to Employee Share-Based Payment Accounting (“ASU 2016-09”), which updates several aspects of the accounting for share-based payment transactions, including recognition of excess tax benefits and deficiencies, the classification of those excess tax benefits on the statement of cash flows, an accounting policy election for forfeitures, the amount an employer can withhold to cover income taxes and still qualify for equity classification and the classification of those taxes paid on the statement of cash flows. In accordance with the new guidance, the Company recorded a $2.7 million cumulative-effect adjustment to retained earnings on the Company’s Condensed Consolidated Balance Sheet as of June 30, 2017, which included recognition of excess tax benefits and deficiencies and the removal of the estimated forfeiture rate. ASU 2016-09 was applied on a modified retrospective basis and prior periods were not retrospectively adjusted.
Inventory. In the first quarter of 2017, the Company adopted Accounting Standards Update No. 2015-11, Simplifying the Measurement of Inventory (“ASU 2015-11”), which changes the inventory measurement principle from lower of cost or market to lower of cost and net realizable value for entities using the first-in, first-out or average cost methods. ASU 2015-11 was

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applied on a prospective basis and prior periods were not retrospectively adjusted. There was no material impact as a result of adoption as of June 30, 2017.
Recent Accounting Pronouncements
Revenue recognition. In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”). The objective of ASU 2014-09 is greater consistency and comparability across industries by using a five-step model to recognize revenue from customer contracts. ASU 2014-09 also contains some new disclosure requirements under GAAP. In August 2015, the FASB issued Accounting Standards Update No. 2015-14, Deferral of the Effective Date (“ASU 2015-14”). ASU 2015-14 defers the effective date of the new revenue standard by one year, making it effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. In 2016, the FASB issued additional accounting standards updates to clarify the implementation guidance of ASU 2014-09. The Company is currently evaluating the effect that adopting this guidance will have on its financial position, cash flows and results of operations.
Financial instruments. In January 2016, the FASB issued Accounting Standards Update No. 2016-01, Recognition and Measurement of Financial Assets and Financial Liabilities (“ASU 2016-01”), which requires that most equity instruments be measured at fair value with subsequent changes in fair value recognized in net income. ASU 2016-01 also impacts financial liabilities under the fair value option and the presentation and disclosure requirements for financial instruments. ASU 2016-01 does not apply to equity method investments or investments in consolidated subsidiaries. ASU 2016-01 is effective for fiscal years beginning after December 15, 2017, including interim periods within those years. The Company is currently evaluating the effect that adopting this guidance will have on its financial position, cash flows and results of operations.
Leases. In February 2016, the FASB issued Accounting Standards Update No. 2016-02, Leases (“ASU 2016-02”), which requires a lessee to recognize lease payment obligations and a corresponding right-of-use asset to be measured at fair value on the balance sheet. ASU 2016-02 also requires certain qualitative and quantitative disclosures about the amount, timing and uncertainty of cash flows arising from leases. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, including interim periods within those years. The Company is currently evaluating the effect that adopting this guidance will have on its financial position, cash flows and results of operations.
Statement of cash flows. In August 2016, the FASB issued Accounting Standards Update No. 2016-15, Statement of Cash Flows (“ASU 2016-15”), which is intended to reduce diversity in practice in how certain transactions are classified in the statement of cash flows. ASU 2016-15 is effective for fiscal years beginning after December 15, 2017, including interim periods within those years. The adoption of this guidance will not impact the Company’s financial position or results of operations, but could result in presentation changes on the Company’s statement of cash flows.
Business combinations. In January 2017, the FASB issued Accounting Standards Update No. 2017-01, Clarifying the Definition of a Business (“ASU 2017-01”), which provides guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. ASU 2017-01 requires entities to use a screen test to determine when an integrated set of assets and activities is not a business or if the integrated set of assets and activities needs to be further evaluated against the framework. ASU 2017-01 is effective for fiscal years beginning after December 15, 2017, including interim periods within those years. The Company is currently evaluating the effect that adopting this guidance will have on its financial position, cash flows and results of operations.
Stock-based compensation. In May 2017, the FASB issued Accounting Standards Update No. 2017-09, Scope of Modification Accounting (“ASU 2017-09”), which provides guidance about which changes to the terms or conditions of a share-based payment award require an entity to apply modification accounting. The adoption of ASU 2017-09 will become effective for annual periods beginning after December 15, 2017, and the Company is currently evaluating the impact that it will have on its financial position, cash flows and results of operations.
3. Inventory
Crude oil inventory includes oil in tank. Equipment and materials consist primarily of proppant, chemicals, tubular goods, well equipment to be used in future drilling or repair operations and well fracturing equipment. Crude oil inventory and equipment and materials are included in Inventory on the Company’s Condensed Consolidated Balance Sheets.
The minimum volume of product in a pipeline system that enables the system to operate is known as linefill and is generally not available to be withdrawn from the pipeline system until the expiration of the transportation contract. The Company owns oil linefill in third-party pipelines, which is included in Long-term inventory on the Company’s Condensed Consolidated Balance Sheets.

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Inventory, including long-term inventory, is stated at the lower of cost and net realizable value with cost determined on an average cost method. The Company assesses the carrying value of inventory and uses estimates and judgment when making any adjustments necessary to reduce the carrying value to net realizable value. Among the uncertainties that impact the Company’s estimates are the applicable quality and location differentials to include in the Company’s net realizable value analysis. Additionally, the Company estimates the upcoming liquidation timing of the inventory. Changes in assumptions made as to the timing of a sale can materially impact net realizable value.
Total inventory consists of the following:
 
June 30, 2017
 
December 31, 2016
 
(In thousands)
Inventory
 
 
 
Crude oil inventory
$
7,846

 
$
7,086

Equipment and materials
10,096

 
3,562

Total inventory
$
17,942

 
$
10,648

 
 
 
 
Long-term inventory
 
 
 
Linefill in third-party pipelines
$
8,762

 
$
—

Long-term inventory
$
8,762

 
$
—

 
 
 
 
Total
$
26,704

 
$
10,648

4. Fair Value Measurements
In accordance with the FASB’s authoritative guidance on fair value measurements, the Company’s financial assets and liabilities are measured at fair value on a recurring basis. The Company’s financial instruments, including certain cash and cash equivalents, accounts receivable, accounts payable and other payables, are carried at cost, which approximates their respective fair market values due to their short-term maturities. The Company recognizes its non-financial assets and liabilities, such as asset retirement obligations (“ARO”) and proved oil and natural gas properties upon impairment, at fair value on a non-recurring basis.
As defined in the authoritative guidance, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). To estimate fair value, the Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable.
The authoritative guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (“Level 1” measurements) and the lowest priority to unobservable inputs (“Level 3” measurements). The three levels of the fair value hierarchy are as follows:
Level 1 — Unadjusted quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
Level 2 — Pricing inputs, other than unadjusted quoted prices in active markets included in Level 1, are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument and can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.
Level 3 — Pricing inputs are generally less observable from objective sources, requiring internally developed valuation methodologies that result in management’s best estimate of fair value.
Financial Assets and Liabilities
Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. The following tables

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set forth by level, within the fair value hierarchy, the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis:
 
Fair value at June 30, 2017
 
Level 1
 
Level 2
 
Level 3
 
Total
 
(In thousands)
Assets:
 
 
 
 
 
 
 
Money market funds
$
142

 
$
—

 
$
—

 
$
142

Commodity derivative instruments (see Note 5)
—

 
43,685

 
—

 
43,685

Total assets
$
142

 
$
43,685

 
$
—

 
$
43,827

 
Fair value at December 31, 2016
 
Level 1
 
Level 2
 
Level 3
 
Total
 
(In thousands)
Assets:
 
 
 
 
 
 
 
Money market funds
$
141

 
$
—

 
$
—

 
$
141

Commodity derivative instruments (see Note 5)
—

 
362

 
—

 
362

Total assets
$
141

 
$
362

 
$
—

 
$
503

Liabilities:
 
 
 
 
 
 
 
Commodity derivative instruments (see Note 5)
$
—

 
$
72,183

 
$
—

 
$
72,183

Total liabilities
$
—

 
$
72,183

 
$
—

 
$
72,183

The Level 1 instruments presented in the tables above consist of money market funds included in cash and cash equivalents on the Company’s Condensed Consolidated Balance Sheets at June 30, 2017 and December 31, 2016. The Company’s money market funds represent cash equivalents backed by the assets of high-quality major banks and financial institutions. The Company identifies the money market funds as Level 1 instruments because the money market funds have daily liquidity, quoted prices for the underlying investments can be obtained, and there are active markets for the underlying investments.
The Level 2 instruments presented in the tables above consist of commodity derivative instruments, which include oil and natural gas swaps and collars. The fair values of the Company’s commodity derivative instruments are based upon a third-party preparer’s calculation using mark-to-market valuation reports provided by the Company’s counterparties for monthly settlement purposes to determine the valuation of its derivative instruments. The Company has the third-party preparer evaluate other readily available market prices for its derivative contracts, as there is an active market for these contracts. The third-party preparer performs its independent valuation using a moment matching method similar to Turnbull-Wakeman for Asian options. The significant inputs used are crude oil prices, volatility, skew, discount rate and the contract terms of the derivative instruments. The Company compares the third-party preparer’s valuation to counterparty valuation statements, investigating any significant differences, and analyzes monthly valuation changes in relation to movements in crude oil and natural gas forward price curves. The determination of the fair value for derivative instruments also incorporates a credit adjustment for non-performance risk, as required by GAAP. The Company calculates the credit adjustment for derivatives in a net asset position using current credit default swap values for each counterparty. The credit adjustment for derivatives in a net liability position is based on the Company’s market credit spread. Based on these calculations, the Company recorded an adjustment to reduce the fair value of its net derivative asset by $41,000 at June 30, 2017 and an adjustment to reduce the fair value of its net derivative liability by $2.0 million at December 31, 2016.
There were no transfers between fair value levels during the six months ended June 30, 2017 and 2016.

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5. Derivative Instruments
The Company utilizes derivative financial instruments to manage risks related to changes in oil and natural gas prices. The Company’s crude oil and natural gas contracts will settle monthly based on the average NYMEX West Texas Intermediate crude oil index price (“WTI”) and the average NYMEX Henry Hub natural gas index price (“Henry Hub”), respectively. At June 30, 2017, the Company utilized swaps and two-way and three-way costless collar options to reduce the volatility of oil and natural gas prices on a significant portion of its future expected oil and natural gas production. A swap is a sold call and a purchased put established at the same price (both ceiling and floor), which the Company will receive for the volumes under contract. A two-way collar is a combination of options: a sold call and a purchased put. The purchased put establishes a minimum price (floor) and the sold call establishes a maximum price (ceiling) the Company will receive for the volumes under contract. A three-way collar is a combination of options: a sold call, a purchased put and a sold put. The purchased put establishes a minimum price (floor), unless the market price falls below the sold put (sub-floor), at which point the minimum price would be the NYMEX index price plus the difference between the purchased put and the sold put strike price. The sold call establishes a maximum price (ceiling) the Company will receive for the volumes under contract.
All derivative instruments are recorded on the Company’s Condensed Consolidated Balance Sheets as either assets or liabilities measured at fair value (see Note 4 – Fair Value Measurements). The Company has not designated any derivative instruments as hedges for accounting purposes and does not enter into such instruments for speculative trading purposes. If a derivative does not qualify as a hedge or is not designated as a hedge, the changes in fair value are recognized in the other income (expense) section of the Company’s Condensed Consolidated Statements of Operations as a net gain or loss on derivative instruments. The Company’s cash flow is only impacted when the actual settlements under the derivative contracts result in making a payment to or receiving a payment from the counterparty. These cash settlements represent the cumulative gains and losses on the Company’s derivative instruments and do not include a recovery of costs that were paid to acquire or modify the derivative instruments that were settled. Cash settlements are reflected as investing activities in the Company’s Condensed Consolidated Statements of Cash Flows.
At June 30, 2017, the Company had the following outstanding commodity derivative instruments:
Commodity

Settlement
Period

Derivative
Instrument

Volumes

Weighted Average Prices

Fair Value
Asset (Liability)




Swap

Sub-Floor

Floor

Ceiling



 

 






(In thousands)
Crude oil

2017

Swaps

3,843,000

Bbl

$
49.83

 
 
 
 
 
 

$
13,211

Crude oil

2017

Two-way collar

1,464,000

Bbl

 
 
 
 
$
46.25

 
$
54.37


3,122

Crude oil

2017

Three-way collar

1,098,000

Bbl

 
 
$
31.67

 
$
45.83

 
$
59.94


1,816

Crude oil

2018

Swaps

5,508,000

Bbl

$
51.95

 
 
 
 
 
 

20,746

Crude oil

2018

Two-way collar

582,000

Bbl

 
 
 
 
$
48.40

 
$
55.13


1,799

Crude oil

2018

Three-way collar

186,000

Bbl

 
 
$
31.67

 
$
45.83

 
$
59.94


452

Crude oil

2019

Swaps

434,000

Bbl

$
52.16

 
 
 
 
 
 

1,365

Crude oil

2019

Two-way collar

31,000

Bbl

 
 
 
 
$
50.00

 
$
55.70


104

Natural gas
 
2017
 
Swaps
 
3,680,000

MMBtu
 
$
3.32

 
 
 
 
 
 
 
827

Natural gas
 
2018
 
Swaps
 
5,475,000

MMBtu
 
$
3.04

 
 
 
 
 
 
 
243













 

 


$
43,685

The following table summarizes the location and amounts of gains and losses from the Company’s commodity derivative instruments recorded in the Company’s Condensed Consolidated Statements of Operations for the periods presented:
 
 
Three Months Ended June 30,
 
Six Months Ended June 30,
Statement of Operations Location
 
2017
 
2016
 
2017
 
2016
 
 
(In thousands)
Net gain (loss) on derivative instruments
 
$
50,532

 
$
(90,846
)
 
$
106,607

 
$
(76,471
)
In accordance with the FASB’s authoritative guidance on disclosures about offsetting assets and liabilities, the Company is required to disclose both gross and net information about instruments and transactions eligible for offset in the statement of financial position as well as instruments and transactions subject to an agreement similar to a master netting agreement. The Company’s derivative instruments are presented as assets and liabilities on a net basis by counterparty, as all counterparty contracts provide for net settlement. No margin or collateral balances are deposited with counterparties, and as such, gross amounts are offset to determine the net amounts presented in the Company’s Condensed Consolidated Balance Sheets.

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The following table summarizes the location and fair value of all outstanding commodity derivative instruments recorded in the Company’s Condensed Consolidated Balance Sheets: 
 
 
 
 
June 30, 2017
Commodity
 
Balance Sheet Location
 
Gross Recognized Assets
 
Gross Amount Offset
 
Net Recognized Fair Value Assets
 
 
 
 
(In thousands)
Derivatives assets:
 
 
 
 
 
 
 
 
Commodity contracts
 
Derivative instruments — current assets
 
$
37,829

 
$
(5,978
)
 
$
31,851

Commodity contracts
 
Derivative instruments — non-current assets
 
12,482

 
(648
)
 
11,834

Total derivatives assets
 
 
 
$
50,311

 
$
(6,626
)
 
$
43,685

 
 
 
 
 
 
 
 
 
 
 
 
 
December 31, 2016
Commodity
 
Balance Sheet Location
 
Gross Recognized Asset/Liabilities
 
Gross Amount Offset
 
Net Recognized Fair Value Asset/Liabilities
 
 
 
 
(In thousands)
Derivatives assets:
 
 
 
 
 
 
 
 
Commodity contracts
 
Derivative instruments — current assets
 
$
482

 
$
(120
)
 
$
362

Total derivatives assets
 
 
 
$
482

 
$
(120
)
 
$
362

Derivatives liabilities:
 
 
 
 
 
 
 
 
Commodity contracts
 
Derivative instruments — current liabilities
 
$
66,838

 
$
(6,369
)
 
$
60,469

Commodity contracts
 
Derivative instruments — non-current liabilities
 
14,164

 
(2,450
)
 
11,714

Total derivatives liabilities
 
$
81,002

 
$
(8,819
)
 
$
72,183

6. Property, Plant and Equipment
The following table sets forth the Company’s property, plant and equipment:
 
June 30, 2017
 
December 31, 2016
 
(In thousands)
Proved oil and gas properties(1)
$
6,671,833

 
$
6,476,833

Less: accumulated depreciation, depletion, amortization and impairment
(2,130,330
)
 
(1,886,732
)
Proved oil and gas properties, net
4,541,503

 
4,590,101

Unproved oil and gas properties
816,242

 
819,735

Other property and equipment
695,592

 
618,790

Less: accumulated depreciation
(122,323
)
 
(109,059
)
Other property and equipment, net
573,269

 
509,731

Total property, plant and equipment, net
$
5,931,014

 
$
5,919,567

__________________
(1)
Included in the Company’s proved oil and gas properties are estimates of future asset retirement costs of $43.3 million and $42.9 million at June 30, 2017 and December 31, 2016, respectively.
Midstream assets acquisition. On April 25, 2017, the Company completed purchase and sale agreements with two undisclosed private sellers to acquire certain midstream assets in McKenzie County, North Dakota for total consideration of $12.7 million, which includes $4.9 million of installment notes payable. Based on the FASB’s authoritative guidance, the acquisition qualified as a business combination, and as such, the Company estimated the fair value of the assets acquired as of the acquisition date. The Company recorded the assets acquired at their estimated fair value of $12.7 million, which the Company considers to be representative of the price paid by a typical market participant. This measurement resulted in no goodwill or bargain purchase being recognized.
The results of operations for the acquisition have been included in the Company’s condensed consolidated financial statements since the closing date. Pro forma information is not presented as the pro forma results would not be materially different from the information presented in the Company’s Condensed Consolidated Statement of Operations.

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7. Long-Term Debt
The Company’s long-term debt consists of the following:
 
June 30, 2017
 
December 31, 2016
 
(In thousands)
Senior secured revolving line of credit
$
418,000

 
$
363,000

Senior unsecured notes
 
 
 
7.25% senior unsecured notes due February 1, 2019
54,275

 
54,275

6.5% senior unsecured notes due November 1, 2021
395,501

 
395,501

6.875% senior unsecured notes due March 15, 2022
937,080

 
937,080

6.875% senior unsecured notes due January 15, 2023
366,094

 
366,094

2.625% senior unsecured convertible notes due September 15, 2023
300,000

 
300,000

Total principal of senior unsecured notes
2,052,950

 
2,052,950

Less: unamortized deferred financing costs on senior unsecured notes
(25,634
)
 
(28,268
)
Less: unamortized debt discount on senior unsecured convertible notes
(85,633
)
 
(90,468
)
Total long-term debt
$
2,359,683

 
$
2,297,214

The carrying amount of the Company’s long-term debt reported in the Condensed Consolidated Balance Sheet at June 30, 2017 was $2,359.7 million, which included $2,053.0 million of senior unsecured notes, a reduction for the unamortized debt discount related to the equity component of the senior unsecured convertible notes and a reduction for the unamortized deferred financing costs on the senior unsecured notes of $85.6 million and $25.6 million, respectively, and $418.0 million of borrowings under the revolving credit facility. The Company’s revolving credit facility is recorded at a value that approximates its fair value since its variable interest rate is tied to current market rates. The fair value of the Company’s senior unsecured notes, which are publicly traded and therefore categorized as Level 1 liabilities, was $1,994.8 million at June 30, 2017.
Senior secured revolving line of credit. The Company has a senior secured revolving line of credit (the “Credit Facility”) of $2,500.0 million as of June 30, 2017, which has a maturity date of April 13, 2020, provided that the 7.25% senior unsecured notes due February 1, 2019 (the “2019 Notes”), of which $54.3 million is outstanding, are retired or refinanced 90 days prior to their maturity. The Credit Facility is restricted to a borrowing base, which is reserve-based and subject to semi-annual redeterminations on April 1 and October 1 of each year. On April 10, 2017, the lenders under the Credit Facility (the “Lenders”) completed their regular semi-annual redetermination of the borrowing base scheduled for April 1, 2017, resulting in an increase in the borrowing base from $1,150.0 million to $1,600.0 million; however, the Company elected to limit the Lenders’ aggregate commitment to $1,150.0 million.
At June 30, 2017, the Company had $418.0 million of LIBOR loans at a weighted average interest rate of 3.0% and $10.0 million of outstanding letters of credit issued under the Credit Facility, resulting in an unused borrowing base committed capacity of $722.0 million. On a quarterly basis, the Company also pays a 0.375% (as of June 30, 2017) annualized commitment fee on the average amount of borrowing base capacity not utilized during the quarter and fees calculated on the average amount of letter of credit balances outstanding during the quarter.
The Company was in compliance with the financial covenants of the Credit Facility as of June 30, 2017.
Senior unsecured notes. At June 30, 2017, the Company had $1,753.0 million principal amount of senior unsecured notes outstanding with maturities ranging from February 2019 to January 2023 and coupons ranging from 6.50% to 7.25% (the “Senior Notes”). Prior to certain dates, the Company has the option to redeem some or all of the Senior Notes for cash at certain redemption prices equal to a certain percentage of their principal amount plus an applicable make-whole premium and accrued and unpaid interest to the redemption date. The 2019 Notes are currently redeemable for cash at a redemption price equal to par plus accrued and unpaid interest to the redemption date.
Senior unsecured convertible notes. In September 2016, the Company issued $300.0 million of 2.625% senior unsecured convertible notes due September 2023 (the “Senior Convertible Notes”). The Company has the option to settle conversions of these notes with cash, shares of common stock or a combination of cash and common stock at its election. The Company’s intent is to settle the principal amount of the Senior Convertible Notes in cash upon conversion. Prior to March 15, 2023, the Senior Convertible Notes will be convertible only under the following circumstances: (i) during any calendar quarter (and only during such calendar quarter), if the last reported sale price of the Company’s common stock for at least 20 trading days (whether or not consecutive) during the period of 30 consecutive trading days ending on the last trading day of the immediately preceding calendar quarter is greater than or equal to 130% of the conversion price on each applicable trading day; (ii) during the five business day period after any five consecutive trading day period (the “measurement period”) in which the trading

11
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price per $1,000 principal amount of the Senior Convertible Notes for each trading day of the measurement period is less than 98% of the product of the last reported sale price of the Company’s common stock and the conversion rate on each such trading day; or (iii) upon the occurrence of specified corporate events, including certain distributions or a fundamental change. On or after March 15, 2023, the Senior Convertible Notes will be convertible at any time until the second scheduled trading day immediately preceding their September 15, 2023 maturity date. The Senior Convertible Notes will be convertible at an initial conversion rate of 76.3650 shares of the Company’s common stock per $1,000 principal amount of the Senior Convertible Notes, which is equivalent to an initial conversion price of approximately $13.10. The conversion rate will be subject to adjustment in some events but will not be adjusted for any accrued and unpaid interest. In addition, following certain corporate events that occur prior to the maturity date or a notice of redemption, the Company will increase the conversion rate for a holder who elects to convert its Senior Convertible Notes in connection with such corporate event or redemption in certain circumstances. As of June 30, 2017, none of the contingent conditions allowing holders of the Senior Convertible Notes to convert these notes had been met.
Upon issuance, the Company separately accounted for the liability and equity components of the Senior Convertible Notes in accordance with Accounting Standards Codification 470-20. The liability component was recorded at the estimated fair value of a similar debt instrument without the conversion feature. The difference between the principal amount of the Senior Convertible Notes and the estimated fair value of the liability component was recorded as a debt discount and will be amortized to interest expense over the term of the notes using the effective interest method, with an effective interest rate of 8.97% per annum. The fair value of the Senior Convertible Notes as of the issuance date was estimated at $206.8 million, resulting in a debt discount at inception of $93.2 million. The equity component, representing the value of the conversion option, was computed by deducting the fair value of the liability component from the initial proceeds of the Senior Convertible Notes issuance. This equity component was recorded, net of deferred taxes and issuance costs, in additional paid-in capital and will not be remeasured as long as it continues to meet the conditions for equity classification. 
Interest on the Senior Notes and the Senior Convertible Notes (collectively, the “Notes”) is payable semi-annually in arrears. The Notes are guaranteed on a senior unsecured basis by the Company, along with its material subsidiaries (the “Guarantors”), which are 100% owned by the Company. These guarantees are full and unconditional and joint and several among the Guarantors, subject to certain customary release provisions. The indentures governing the Notes contain customary events of default as well as covenants that place restrictions on the Company and certain of its subsidiaries.
8. Asset Retirement Obligations
The following table reflects the changes in the Company’s ARO during the six months ended June 30, 2017:
 
(In thousands)
Balance at December 31, 2016
$
49,687

Liabilities incurred during period
661

Liabilities settled during period
(101
)
Accretion expense during period(1)
1,316

Revisions to estimates
(214
)
Balance at June 30, 2017
$
51,349

___________________
(1) Included in depreciation, depletion and amortization on the Company’s Condensed Consolidated Statements of Operations.
At June 30, 2017, the current portion of the total ARO balance was approximately $0.3 million and was included in accrued liabilities on the Company’s Condensed Consolidated Balance Sheet.
9. Income Taxes
The Company’s effective tax rate for the three and six months ended June 30, 2017 was 12.4% and 31.3%, respectively. The effective tax rate for the three and six months ended June 30, 2017 was lower than the combined federal statutory rate and the statutory rates for the states in which the Company conducts business due to the impact of permanent differences and a forecasted annual pre-tax loss for 2017. The Company’s effective tax rate for the three and six months ended June 30, 2016 was 36.9% and 34.2%, respectively. The effective tax rate for the three and six months ended June 30, 2016 was lower than the combined federal statutory rate and the statutory rates for the states in which the Company conducts business due to the impact of permanent differences on pre-tax loss for the period. During both the three and six months ended June 30, 2017 and 2016, the permanent differences were primarily between amounts expensed for book purposes versus the amounts deductible for income tax purposes related to compensation.

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10. Stock-Based Compensation
Restricted stock awards. The Company has granted restricted stock awards to employees and directors under its Amended and Restated 2010 Long Term Incentive Plan, the majority of which vest over a three-year period. The fair value of restricted stock awards is based on the closing sales price of the Company’s common stock on the date of grant. Compensation expense is recognized ratably over the requisite service period.
During the six months ended June 30, 2017, employees and non-employee directors of the Company were granted restricted stock awards equal to 1,588,010 shares of common stock with a $15.24 weighted average grant date per share value. Stock-based compensation expense recorded for restricted stock awards for the three and six months ended June 30, 2017 was $4.9 million and $10.3 million, respectively, and $4.9 million and $10.7 million for the three and six months ended June 30, 2016, respectively. Stock-based compensation expense is included in general and administrative expenses on the Company’s Condensed Consolidated Statements of Operations.
Performance share units. The Company has granted performance share units (“PSUs”) to officers of the Company under its Amended and Restated 2010 Long Term Incentive Plan. The PSUs are awards of restricted stock units, and each PSU that is earned represents the right to receive one share of the Company’s common stock.
During the six months ended June 30, 2017, officers of the Company were granted 509,800 PSUs with a $16.89 weighted average grant date per share value. Stock-based compensation expense recorded for PSUs for the three and six months ended June 30, 2017 was $2.2 million and $3.5 million, respectively, and $1.3 million and $2.2 million for the three and six months ended June 30, 2016, respectively. Stock-based compensation expense is included in general and administrative expenses on the Company’s Condensed Consolidated Statements of Operations.
The Company accounted for these PSUs as equity awards pursuant to the FASB’s authoritative guidance for share-based payments. The number of PSUs to be earned is subject to a market condition, which is based on a comparison of the total shareholder return (“TSR”) achieved with respect to shares of the Company’s common stock against the TSR achieved by a defined peer group at the end of the performance periods. Depending on the Company’s TSR performance relative to the defined peer group, award recipients will earn between 0% and 200% of the initial PSUs granted. All compensation expense related to the PSUs will be recognized if the requisite performance period is fulfilled, even if the market condition is not achieved.
The aggregate grant date fair value of the market-based awards was determined using a Monte Carlo simulation model. The Monte Carlo simulation model uses assumptions regarding random projections and must be repeated numerous times to achieve a probabilistic assessment. The key valuation assumptions for the Monte Carlo model are the forecast period, initial value, risk-free interest rate, volatility and correlation coefficients. The risk-free interest rates are the U.S. Treasury bond rates on the date of grant that correspond to each performance period. The initial value is the average of the volume weighted average prices for the 30 trading days prior to the start of the performance cycle for the Company and each of its peers. Volatility was calculated from the daily historical returns of 30-day volume weighted average stock prices over a historical period for the Company and each of its peers. The correlation coefficients are measures of the strength of the linear relationship between and amongst the Company and its peers estimated based on historical stock price data.
The following assumptions were used for the Monte Carlo model to determine the grant date fair value and associated stock-based compensation expense of the PSUs granted during the six months ended June 30, 2017:
Risk-free interest rate
1.18% - 1.66%

Oasis volatility
17.16
%

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11. Earnings (Loss) Per Share
Basic earnings (loss) per share is computed by dividing the earnings (loss) attributable to common stockholders by the weighted average number of shares outstanding for the periods presented. The calculation of diluted earnings (loss) per share includes the potential dilutive impact of unvested restricted stock awards and contingently issuable shares related to PSUs and senior convertible notes during the periods presented, unless their effect is anti-dilutive. There are no adjustments made to the income (loss) available to common stockholders in the calculation of diluted earnings (loss) per share.
The following is a calculation of the basic and diluted weighted average shares outstanding for the three and six months ended June 30, 2017 and 2016: 
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2017
 
2016
 
2017
 
2016
 
(In thousands)
Basic weighted average common shares outstanding
233,283

 
176,984

 
233,176

 
169,953

Dilutive effect of restricted stock awards and PSUs(1)
1,634

 
—

 
3,105

 
—

Diluted weighted average common shares outstanding
234,917

 
176,984

 
236,281

 
169,953

__________________ 
(1)
No unvested stock awards were included in computing loss per share for the three and six months ended June 30, 2016 because the effect was anti-dilutive.
The following is a calculation of weighted average common shares excluded from diluted earnings (loss) per share due to the anti-dilutive effect:
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2017
 
2016
 
2017
 
2016
 
(In thousands)
Restricted stock awards and PSUs
4,369

 
4,920

 
2,957

 
4,794

The Company issued its Senior Convertible Notes in September 2016 (see Note 7 – Long-Term Debt). The Company has the option to settle conversions of its Senior Convertible Notes with cash, shares of common stock or a combination of cash and common stock at its election. The Company’s intent is to settle the principal amount of the Senior Convertible Notes in cash upon conversion. As a result, only the amount by which the conversion value exceeds the aggregate principal amount of the notes (conversion spread) is considered in the diluted earnings per share computation under the treasury stock method. As of the three and six months ended June 30, 2017, the conversion value did not exceed the principal amount of the notes, and accordingly, there was no impact to diluted earnings per share for the three and six months ended June 30, 2017.
12. Business Segment Information
The Company’s exploration and production segment is engaged in the acquisition and development of oil and natural gas properties. Revenues for the exploration and production segment are derived from the sale of oil and natural gas production. The Company’s midstream services business segment (OMS) performs salt water gathering and disposal services, fresh water services, natural gas gathering and processing and crude oil gathering and transportation and other midstream services for the Company’s oil and natural gas wells operated by OPNA. Revenues for the midstream segment are primarily derived from salt water pipeline transport, salt water disposal, fresh water sales, natural gas gathering and processing and crude oil gathering, blending, stabilization and transportation. The Company’s well services business segment (OWS) performs completion services for the Company’s oil and natural gas wells operated by OPNA. Revenues for the well services segment are derived from providing well services, product sales and equipment rentals. The revenues and expenses related to work performed by OMS and OWS for OPNA’s working interests are eliminated in consolidation, and only the revenues and expenses related to non-affiliated working interest owners are included in the Company’s Condensed Consolidated Statements of Operations. These segments represent the Company’s three operating units, each offering different products and services. The Company’s corporate activities have been allocated to the supported business segments accordingly.

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Management evaluates the performance of the Company’s business segments based on operating income. The following table summarizes financial information for the Company’s three business segments for the periods presented: 
 
Exploration and
Production
 
Midstream Services
 
Well Services
 
Eliminations
 
Consolidated
 
(In thousands)
Three months ended June 30, 2017:
 
Revenues from non-affiliates
$
226,724

 
$
15,566

 
$
11,801

 
$
—

 
$
254,091

Inter-segment revenues
—

 
24,746

 
21,650

 
(46,396
)
 
—

Total revenues
226,724

 
40,312

 
33,451

 
(46,396
)
 
254,091

Operating income (loss)
(17,425
)
 
23,103

 
1,950

 
(2,249
)
 
5,379

Other income
13,525

 
3

 
—

 
—

 
13,528

Income (loss) before income taxes
$
(3,900
)
 
$
23,106

 
$
1,950

 
$
(2,249
)
 
$
18,907

 
 
Three months ended June 30, 2016:
 
Revenues from non-affiliates
$
159,337

 
$
6,910

 
$
12,833

 
$
—

 
$
179,080

Inter-segment revenues
—

 
22,025

 
8,302

 
(30,327
)
 
—

Total revenues
159,337

 
28,935

 
21,135

 
(30,327
)
 
179,080

Operating income (loss)
(44,748
)
 
18,056

 
(2,173
)
 
651

 
(28,214
)
Other income (expense)
(114,230
)
 
(16
)
 
31

 
—

 
(114,215
)
Income (loss) before income taxes
$
(158,978
)
 
$
18,040

 
$
(2,142
)
 
$
651

 
$
(142,429
)
 
 
Six months ended June 30, 2017:
 
Revenues from non-affiliates
$
491,607

 
$
30,172

 
$
17,428

 
$
—

 
$
539,207

Inter-segment revenues
—

 
47,781

 
37,003

 
(84,784
)
 
—

Total revenues
491,607

 
77,953

 
54,431

 
(84,784
)
 
539,207

Operating income (loss)
(16,456
)
 
43,865

 
(1,641
)
 
(297
)
 
25,471

Other income
33,292

 
2

 
4

 
—

 
33,298

Income (loss) before income taxes
$
16,836

 
$
43,867

 
$
(1,637
)
 
$
(297
)
 
$
58,769

 
 
Six months ended June 30, 2016:
 
Revenues from non-affiliates
$
276,652

 
$
13,893

 
$
18,818

 
$
—

 
$
309,363

Inter-segment revenues
—

 
44,860

 
33,205

 
(78,065
)
 
—

Total revenues
276,652

 
58,753

 
52,023

 
(78,065
)
 
309,363

Operating income (loss)
(133,625
)
 
33,200

 
1,848

 
(4,852
)
 
(103,429
)
Other income (expense)
(131,119
)
 
(2
)
 
37

 
—

 
(131,084
)
Income (loss) before income taxes
$
(264,744
)
 
$
33,198

 
$
1,885

 
$
(4,852
)
 
$
(234,513
)
 
 
At June 30, 2017:
 
Property, plant and equipment, net
$
5,567,347

 
$
495,112

 
$
41,228

 
$
(172,673
)
 
$
5,931,014

Total assets(1)
5,881,351

 
504,119

 
48,924

 
(172,673
)
 
6,261,721

At December 31, 2016:
 
 
 
 
 
 
 
 
 
Property, plant and equipment, net
$
5,620,558

 
$
424,197

 
$
47,189

 
$
(172,377
)
 
$
5,919,567

Total assets(1)
5,868,747

 
431,095

 
51,167

 
(172,377
)
 
6,178,632

___________________
(1)
Intercompany receivables (payables) for all segments were reclassified to capital contributions from (distributions to) parent and not included in total assets.

15
Table of Contents

13. Commitments and Contingencies
The Company has various contractual obligations in the normal course of its operations. As of June 30, 2017, there have been no material changes to the Company’s future commitments as disclosed in Note 16 in the Company’s 2016 Annual Report.
Litigation. The Company is party to various legal and/or regulatory proceedings from time to time arising in the ordinary course of business. When the Company determines that a loss is probable of occurring and is reasonably estimable, the Company accrues an undiscounted liability for such contingencies based on its best estimate using information available at the time. The Company discloses contingencies where an adverse outcome may be material, or in the judgment of management, the matter should otherwise be disclosed.
Mirada litigation. On March 23, 2017, Mirada Energy, LLC, Mirada Wild Basin Holding Company, LLC and Mirada Energy Fund I, LLC (collectively, “Mirada”) filed a lawsuit against Oasis, OPNA and OMS, seeking monetary damages in excess of $100 million, declaratory relief, attorneys’ fees and costs (Mirada Energy, LLC, et al. v. Oasis Petroleum North America LLC, et al.; in the 334th Judicial District Court of Harris County, Texas; Case Number 2017-19911). Mirada asserts that it is a working interest owner in certain acreage owned and operated by the Company in Wild Basin. Specifically, Mirada asserts that the Company has breached certain agreements by: (1) failing to allow Mirada to participate in the Company’s midstream operations in Wild Basin; (2) refusing to provide Mirada with information that Mirada contends is required under certain agreements and failing to provide information in a timely fashion; (3) failing to consult with Mirada and failing to obtain Mirada’s consent prior to drilling more than one well at a time in Wild Basin; and (4) by overstating the estimated costs of proposed well operations in Wild Basin. Mirada seeks a declaratory judgment that the Company be removed as operator in Wild Basin at Mirada’s election and that Mirada be allowed to elect a new operator; certain agreements apply to the Company and Mirada and Wild Basin with respect to this dispute; the Company be required to provide all information within its possession regarding proposed or ongoing operations in Wild Basin; and the Company not be permitted to drill, or propose to drill, more than one well at a time in Wild Basin without obtaining Mirada’s consent. Mirada also seeks a declaratory judgment with respect to the Company’s current midstream operations in Wild Basin. Specifically, Mirada seeks a declaratory judgment that Mirada has a right to participate in the Company’s Wild Basin midstream operations, consisting of produced water disposal, crude oil gathering and gas gathering and processing; that, upon Mirada’s election to participate, Mirada is obligated to pay its proportionate costs of the Company’s midstream operations in Wild Basin; and that Mirada would then be entitled to receive a share of revenues from the midstream operations and would not be charged any amount for its use of these facilities for production from the “Contract Area.”
On June 30, 2017, Mirada amended its original petition to add a claim that the Company has breached certain agreements by charging Mirada for midstream services provided by its affiliates and to seek a declaratory judgment that Mirada is entitled to be paid its share of total proceeds from the sale of hydrocarbons received by OPNA or any affiliate of OPNA without deductions for midstream services provided by OPNA or its affiliates.
The Company believes that Mirada’s claims are without merit, that the Company has complied with its obligations under the applicable agreements and that some of Mirada’s claims are grounded in agreements which do not apply to the Company. The Company filed an answer denying Mirada’s claims on April 21, 2017, and intends to vigorously defend against Mirada’s claims. Discovery is ongoing, and trial is currently scheduled for July 2018. However, the Company cannot predict or guarantee the ultimate outcome or resolution of such matter. If such matter were to be determined adversely to the Company’s interests, or if the Company were forced to settle such matter for a significant amount, such resolution or settlement could have a material adverse effect on the Company’s business, results of operations and financial condition. Such an adverse determination could materially impact the Company’s ability to operate its properties in Wild Basin or develop its identified drilling locations in Wild Basin on its current development schedule. A determination that Mirada has a right to participate in the Company’s midstream operations could materially reduce the interests of the Company in their current assets and future midstream opportunities and related revenues in Wild Basin.

16
Table of Contents

14. Condensed Consolidating Financial Information
The Notes (see Note 7 – Long-Term Debt) are guaranteed on a senior unsecured basis by the Guarantors, which are 100% owned by the Company. These guarantees are full and unconditional and joint and several among the Guarantors. Certain of the Company’s immaterial wholly-owned subsidiaries do not guarantee the Notes (“Non-Guarantor Subsidiaries”).
The following financial information reflects consolidating financial information of the parent company, Oasis Petroleum Inc. (“Issuer”), and its Guarantors on a combined basis, prepared on the equity basis of accounting. The Non-Guarantor Subsidiaries are immaterial and, therefore, not presented separately. The information is presented in accordance with the requirements of Rule 3-10 under the SEC’s Regulation S-X. The financial information may not necessarily be indicative of results of operations, cash flows or financial position had the Guarantors operated as independent entities. The Company has not presented separate financial and narrative information for each of the Guarantors because it believes such financial and narrative information would not provide any additional information that would be material in evaluating the sufficiency of the Guarantors.


17
Table of Contents

Condensed Consolidating Balance Sheet
 
June 30, 2017
 
Parent/
Issuer
 
Combined
Guarantor
Subsidiaries
 
Intercompany
Eliminations
 
Consolidated
 
(In thousands)
ASSETS
 
 
 
 
 
 
 
Current assets
 
 
 
 
 
 
 
Cash and cash equivalents
$
178

 
$
11,262

 
$
—

 
$
11,440

Accounts receivable, net
—

 
218,302

 
—

 
218,302

Accounts receivable - affiliates
187,496

 
33,709

 
(221,205
)
 
—

Inventory
—

 
17,942

 
—

 
17,942

Prepaid expenses
664

 
9,946

 
—

 
10,610

Derivative instruments
—

 
31,851

 
—

 
31,851

Other current assets
3

 
59

 
—

 
62

Total current assets
188,341

 
323,071

 
(221,205
)
 
290,207

Property, plant and equipment


 


 


 


Oil and gas properties (successful efforts method)
—

 
7,488,075

 
—

 
7,488,075

Other property and equipment
—

 
695,592

 
—

 
695,592

Less: accumulated depreciation, depletion, amortization and impairment
—

 
(2,252,653
)
 
—

 
(2,252,653
)
Total property, plant and equipment, net
—

 
5,931,014

 
—

 
5,931,014

Investments in and advances to subsidiaries
4,545,805

 
—

 
(4,545,805
)
 
—

Derivative instruments
—

 
11,834

 
—

 
11,834

Deferred income taxes
257,652

 
—

 
(257,652
)
 
—

Long-term inventory
—

 
8,762

 
—

 
8,762

Other assets
—

 
19,904

 
—

 
19,904

Total assets
$
4,991,798

 
$
6,294,585

 
$
(5,024,662
)
 
$
6,261,721

LIABILITIES AND STOCKHOLDERS’ EQUITY
 
 
 
 
 
 
 
Current liabilities
 
 
 
 
 
 
 
Accounts payable
$
—

 
$
12,257

 
$
—

 
$
12,257

Accounts payable - affiliates
33,709

 
187,496

 
(221,205
)
 
—

Revenues and production taxes payable
—

 
143,715

 
—

 
143,715

Accrued liabilities
—

 
139,766

 
—

 
139,766

Accrued interest payable
38,796

 
332

 
—

 
39,128

Advances from joint interest partners
—

 
5,816

 
—

 
5,816

Total current liabilities
72,505

 
489,382

 
(221,205
)
 
340,682

Long-term debt
1,941,683

 
418,000

 
—

 
2,359,683

Deferred income taxes
—

 
784,833

 
(257,652
)
 
527,181

Asset retirement obligations
—

 
51,059

 
—

 
51,059

Other liabilities
—

 
5,506

 
—

 
5,506

Total liabilities
2,014,188

 
1,748,780

 
(478,857
)
 
3,284,111

Stockholders’ equity
 
 
 
 
 
 
 
Capital contributions from affiliates
—

 
3,395,528

 
(3,395,528
)
 
—

Common stock, $0.01 par value: 450,000,000 shares authorized; 238,642,598 shares issued and 237,410,395 shares outstanding
2,345

 
—

 
—

 
2,345

Treasury stock, at cost: 1,232,203 shares
(21,401
)
 
—

 
—

 
(21,401
)
Additional paid-in-capital
2,362,084

 
8,743

 
(8,743
)
 
2,362,084

Retained earnings
634,582

 
1,141,534

 
(1,141,534
)
 
634,582

Total stockholders’ equity
2,977,610

 
4,545,805

 
(4,545,805
)
 
2,977,610

Total liabilities and stockholders’ equity
$
4,991,798

 
$
6,294,585

 
$
(5,024,662
)
 
$
6,261,721


18
Table of Contents

Condensed Consolidating Balance Sheet
 
December 31, 2016
 
Parent/
Issuer
 
Combined
Guarantor
Subsidiaries
 
Intercompany
Eliminations
 
Consolidated
 
(In thousands)
ASSETS
 
 
 
 
 
 
 
Current assets
 
 
 
 
 
 
 
Cash and cash equivalents
$
166

 
$
11,060

 
$
—

 
$
11,226

Accounts receivable, net
—

 
204,335

 
—

 
204,335

Accounts receivable - affiliates
252,000

 
27,619

 
(279,619
)
 
—

Inventory
—

 
10,648

 
—

 
10,648

Prepaid expenses
275

 
7,348

 
—

 
7,623

Derivative instruments
—

 
362

 
—

 
362

Other current assets
—

 
4,355

 
—

 
4,355

Total current assets
252,441

 
265,727

 
(279,619
)
 
238,549

Property, plant and equipment


 


 


 


Oil and gas properties (successful efforts method)
—

 
7,296,568

 
—

 
7,296,568

Other property and equipment
—

 
618,790

 
—

 
618,790

Less: accumulated depreciation, depletion, amortization and impairment
—

 
(1,995,791
)
 
—

 
(1,995,791
)
Total property, plant and equipment, net
—

 
5,919,567

 
—

 
5,919,567

Investments in and advances to subsidiaries
4,451,192

 
—

 
(4,451,192
)
 
—

Derivative instruments
—

 
—

 
—

 
—

Deferred income taxes
220,058

 
—

 
(220,058
)
 
—

Other assets
—

 
20,516

 
—

 
20,516

Total assets
$
4,923,691

 
$
6,205,810

 
$
(4,950,869
)
 
$
6,178,632

LIABILITIES AND STOCKHOLDERS’ EQUITY
 
 
 
 
 
 
 
Current liabilities
 
 
 
 
 
 
 
Accounts payable
$
—

 
$
4,645

 
$
—

 
$
4,645

Accounts payable - affiliates
27,619

 
252,000

 
(279,619
)
 
—

Revenues and production taxes payable
—

 
139,737

 
—

 
139,737

Accrued liabilities
12

 
119,161

 
—

 
119,173

Accrued interest payable
38,689

 
315

 
—

 
39,004

Derivative instruments
—

 
60,469

 
—

 
60,469

Advances from joint interest partners
—

 
7,597

 
—

 
7,597

Other current liabilities
—

 
10,490

 
—

 
10,490

Total current liabilities
66,320

 
594,414

 
(279,619
)
 
381,115

Long-term debt
1,934,214

 
363,000

 
—

 
2,297,214

Deferred income taxes
—

 
733,587

 
(220,058
)
 
513,529

Asset retirement obligations
—

 
48,985

 
—

 
48,985

Derivative instruments
—

 
11,714

 
—

 
11,714

Other liabilities
—

 
2,918

 
—

 
2,918

Total liabilities
2,000,534

 
1,754,618

 
(499,677
)
 
3,255,475

Stockholders’ equity
 
 
 
 
 
 
 
Capital contributions from affiliates
—

 
3,388,893

 
(3,388,893
)
 
—

Common stock, $0.01 par value: 450,000,000 shares authorized; 237,201,064 shares issued and 236,344,172 shares outstanding
2,331

 
—

 
—

 
2,331

Treasury stock, at cost: 856,892 shares
(15,950
)
 
—

 
—

 
(15,950
)
Additional paid-in-capital
2,345,271

 
8,743

 
(8,743
)
 
2,345,271

Retained earnings
591,505

 
1,053,556

 
(1,053,556
)
 
591,505

Total stockholders’ equity
2,923,157

 
4,451,192

 
(4,451,192
)
 
2,923,157

Total liabilities and stockholders’ equity
$
4,923,691

 
$
6,205,810

 
$
(4,950,869
)
 
$
6,178,632


19
Table of Contents


Condensed Consolidating Statement of Operations
 
Three Months Ended June 30, 2017
 
Parent/
Issuer
 
Combined
Guarantor
Subsidiaries
 
Intercompany
Eliminations
 
Consolidated
 
(In thousands)
Revenues
 
 
 
 
 
 
 
Oil and gas revenues
$
—

 
$
218,633

 
$
—

 
$
218,633

Bulk oil sales
—

 
8,091

 
—

 
8,091

Midstream revenues
—

 
15,566

 
—

 
15,566

Well services revenues
—

 
11,801

 
—

 
11,801

Total revenues
—

 
254,091

 
—

 
254,091

Operating expenses
 
 
 
 
 
 
 
Lease operating expenses
—

 
44,665

 
—

 
44,665

Midstream operating expenses
—

 
3,263

 
—

 
3,263

Well services operating expenses
—

 
8,088

 
—

 
8,088

Marketing, transportation and gathering expenses
—

 
12,039

 
—

 
12,039

Bulk oil purchases
—

 
7,980

 
—

 
7,980

Production taxes
—

 
18,971

 
—

 
18,971

Depreciation, depletion and amortization
—

 
125,291

 
—

 
125,291

Exploration expenses
—

 
1,667

 
—

 
1,667

Impairment
—

 
3,200

 
—

 
3,200

General and administrative expenses
7,534

 
16,014

 
—

 
23,548

Total operating expenses
7,534

 
241,178

 
—

 
248,712

Operating income (loss)
(7,534
)
 
12,913

 
—

 
5,379

Other income (expense)
 
 
 
 
 
 
 
Equity in earnings of subsidiaries
38,875

 
—

 
(38,875
)
 
—

Net gain on derivative instruments
—

 
50,532

 
—

 
50,532

Interest expense, net of capitalized interest
(33,006
)
 
(3,832
)
 
—

 
(36,838
)
Other expense
—

 
(166
)
 
—

 
(166
)
Total other income
5,869

 
46,534

 
(38,875
)
 
13,528

Income (loss) before income taxes
(1,665
)
 
59,447

 
(38,875
)
 
18,907

Income tax benefit (expense)
18,233

 
(20,572
)
 
—

 
(2,339
)
Net income
$
16,568

 
$
38,875

 
$
(38,875
)
 
$
16,568


20
Table of Contents

Condensed Consolidating Statement of Operations
 
Three Months Ended June 30, 2016
 
Parent/
Issuer
 
Combined
Guarantor
Subsidiaries
 
Intercompany
Eliminations
 
Consolidated
 
(In thousands)
Revenues
 
 
 
 
 
 
 
Oil and gas revenues
$
—

 
$
159,337

 
$
—

 
$
159,337

Midstream revenues
—

 
6,910

 
—

 
6,910

Well services revenues
—

 
12,833

 
—

 
12,833

Total revenues
—

 
179,080

 
—

 
179,080

Operating expenses
 
 
 
 
 
 
 
Lease operating expenses
—

 
31,523

 
—

 
31,523

Midstream operating expenses
—

 
1,740

 
—

 
1,740

Well services operating expenses
—

 
7,135

 
—

 
7,135

Marketing, transportation and gathering expenses
—

 
6,491

 
—

 
6,491

Production taxes
—

 
14,367

 
—

 
14,367

Depreciation, depletion and amortization
—

 
122,488

 
—

 
122,488

Exploration expenses
—

 
340

 
—

 
340

Impairment
—

 
23

 
—

 
23

General and administrative expenses
6,395

 
15,481

 
—

 
21,876

Total operating expenses
6,395

 
199,588

 
—

 
205,983

Loss on sale of properties
—

 
(1,311
)
 
—

 
(1,311
)
Operating loss
(6,395
)
 
(21,819
)
 
—

 
(28,214
)
Other income (expense)
 
 
 
 
 
 
 
Equity in loss of subsidiaries
(71,987
)
 
—

 
71,987

 
—

Net loss on derivative instruments
—

 
(90,846
)
 
—

 
(90,846
)
Interest expense, net of capitalized interest
(33,190
)
 
(1,789
)
 
—

 
(34,979
)
Gain on extinguishment of debt
11,642

 
—

 
—

 
11,642

Other expense
—

 
(32
)
 
—

 
(32
)
Total other expense
(93,535
)
 
(92,667
)
 
71,987

 
(114,215
)
Loss before income taxes
(99,930
)
 
(114,486
)
 
71,987

 
(142,429
)
Income tax benefit
9,999

 
42,499

 
—

 
52,498

Net loss
$
(89,931
)
 
$
(71,987
)
 
$
71,987

 
$
(89,931
)


21
Table of Contents

Condensed Consolidating Statement of Operations
 
Six Months Ended June 30, 2017
 
Parent/
Issuer
 
Combined
Guarantor
Subsidiaries
 
Intercompany
Eliminations
 
Consolidated
 
(In thousands)
Revenues
 
 
 
 
 
 
 
Oil and gas revenues
$
—

 
$
455,885

 
$
—

 
$
455,885

Bulk oil sales
—

 
35,722

 
—

 
35,722

Midstream revenues
—

 
30,172

 
—

 
30,172

Well services revenues
—

 
17,428

 
—

 
17,428

Total revenues
—

 
539,207

 
—

 
539,207

Operating expenses
 
 
 
 
 
 
 
Lease operating expenses
—

 
88,537

 
—

 
88,537

Midstream operating expenses
—

 
6,590

 
—

 
6,590

Well services operating expenses
—

 
11,990

 
—

 
11,990

Marketing, transportation and gathering expenses
—

 
22,990

 
—

 
22,990

Bulk oil purchases
—

 
35,982

 
—

 
35,982

Production taxes
—

 
39,270

 
—

 
39,270

Depreciation, depletion and amortization
—

 
251,957

 
—

 
251,957

Exploration expenses
—

 
3,156

 
—

 
3,156

Impairment
—

 
5,882

 
—

 
5,882

General and administrative expenses
14,599

 
32,783

 
—

 
47,382

Total operating expenses
14,599

 
499,137

 
—

 
513,736

Operating income (loss)
(14,599
)
 
40,070

 
—

 
25,471

Other income (expense)
 
 
 
 
 
 
 
Equity in earnings of subsidiaries
87,978

 
—

 
(87,978
)
 
—

Net gain on derivative instruments
—

 
106,607

 
—

 
106,607

Interest expense, net of capitalized interest
(65,857
)
 
(7,302
)
 
—

 
(73,159
)
Other expense
—

 
(150
)
 
—

 
(150
)
Total other income
22,121

 
99,155

 
(87,978
)
 
33,298

Income before income taxes
7,522

 
139,225

 
(87,978
)
 
58,769

Income tax benefit (expense)
32,871

 
(51,247
)
 
—

 
(18,376
)
Net income
$
40,393

 
$
87,978

 
$
(87,978
)
 
$
40,393


22
Table of Contents

Condensed Consolidating Statement of Operations
 
Six Months Ended June 30, 2016
 
Parent/
Issuer
 
Combined
Guarantor
Subsidiaries
 
Intercompany
Eliminations
 
Consolidated
 
(In thousands)
Revenues
 
 
 
 
 
 
 
Oil and gas revenues
$
—

 
$
276,652

 
$
—

 
$
276,652

Midstream revenues
—

 
13,893

 
—

 
13,893

Well services revenues
—

 
18,818

 
—

 
18,818

Total revenues
—

 
309,363

 
—

 
309,363

Operating expenses
 
 
 
 
 
 
 
Lease operating expenses
—

 
62,587

 
—

 
62,587

Midstream operating expenses
—

 
3,478

 
—

 
3,478

Well services operating expenses
—

 
9,786

 
—

 
9,786

Marketing, transportation and gathering expenses
—

 
15,043

 
—

 
15,043

Production taxes
—

 
25,120

 
—

 
25,120

Depreciation, depletion and amortization
—

 
244,937

 
—

 
244,937

Exploration expenses
—

 
703

 
—

 
703

Impairment
—

 
3,585

 
—

 
3,585

General and administrative expenses
13,846

 
32,396

 
—

 
46,242

Total operating expenses
13,846

 
397,635

 
—

 
411,481

Loss on sale of properties
—

 
(1,311
)
 
—

 
(1,311
)
Operating loss
(13,846
)
 
(89,583
)
 
—

 
(103,429
)
Other income (expense)
 
 
 
 
 
 
 
Equity in loss of subsidiaries
(109,314
)
 
—

 
109,314

 
—

Net loss on derivative instruments
—

 
(76,471
)
 
—

 
(76,471
)
Interest expense, net of capitalized interest
(68,022
)
 
(5,696
)
 
—

 
(73,718
)
Gain on extinguishment of debt
18,658

 
—

 
—

 
18,658

Other income
43

 
404

 
—

 
447

Total other expense
(158,635
)
 
(81,763
)
 
109,314

 
(131,084
)
Loss before income taxes
(172,481
)
 
(171,346
)
 
109,314

 
(234,513
)
Income tax benefit
18,095

 
62,032

 
—

 
80,127

Net loss
$
(154,386
)
 
$
(109,314
)
 
$
109,314

 
$
(154,386
)


23
Table of Contents

Condensed Consolidating Statement of Cash Flows
 
Six Months Ended June 30, 2017
 
Parent/
Issuer
 
Combined
Guarantor
Subsidiaries
 
Intercompany
Eliminations
 
Consolidated
 
(In thousands)
Cash flows from operating activities:
 
 
 
 
 
 
 
Net income
$
40,393

 
$
87,978

 
$
(87,978
)
 
$
40,393

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
 
 
 
 
Equity in earnings of subsidiaries
(87,978
)
 
—

 
87,978

 
—

Depreciation, depletion and amortization
—

 
251,957

 
—

 
251,957

Impairment
—

 
5,882

 
—

 
5,882

Deferred income taxes
(32,871
)
 
51,247

 
—

 
18,376

Derivative instruments
—

 
(106,607
)
 
—

 
(106,607
)
Stock-based compensation expenses
13,395

 
428

 
—

 
13,823

Deferred financing costs amortization and other
7,470

 
1,401

 
—

 
8,871

Working capital and other changes:
 
 
 
 
 
 
 
Change in accounts receivable
64,504

 
(19,833
)
 
(58,414
)
 
(13,743
)
Change in inventory
—

 
(1,007
)
 
—

 
(1,007
)
Change in prepaid expenses
(389
)
 
125

 
—

 
(264
)
Change in other current assets
(3
)
 
283

 
—

 
280

Change in long-term inventory and other assets
—

 
(8,768
)
 
—

 
(8,768
)
Change in accounts payable, interest payable and accrued liabilities
6,185

 
(53,441
)
 
58,414

 
11,158

Change in other current liabilities
—

 
(10,490
)
 
—

 
(10,490
)
Net cash provided by operating activities
10,706

 
199,155

 
—

 
209,861

Cash flows from investing activities:
 
 
 
 
 
 
 
Capital expenditures
—

 
(252,461
)
 
—

 
(252,461
)
Proceeds from sale of properties
—

 
4,000

 
—

 
4,000

Derivative settlements
—

 
(8,899
)
 
—

 
(8,899
)
Advances from joint interest partners
—

 
(1,781
)
 
—

 
(1,781
)
Net cash used in investing activities
—

 
(259,141
)
 
—

 
(259,141
)
Cash flows from financing activities:
 
 
 
 
 
 
 
Proceeds from revolving credit facility
—

 
484,000

 
—

 
484,000

Principal payments on revolving credit facility
—

 
(429,000
)
 
—

 
(429,000
)
Purchases of treasury stock
(5,451
)
 
—

 
—

 
(5,451
)
Investment in / capital contributions from subsidiaries
(5,188
)
 
5,188

 
—

 
—

Other
(55
)
 
—

 
—

 
(55
)
Net cash provided by (used in) financing activities
(10,694
)
 
60,188

 
—

 
49,494

Increase in cash and cash equivalents
12

 
202

 
—

 
214

Cash and cash equivalents at beginning of period
166

 
11,060

 
—

 
11,226

Cash and cash equivalents at end of period
$
178

 
$
11,262

 
$
—

 
$
11,440



24
Table of Contents

Condensed Consolidating Statement of Cash Flows
 
Six Months Ended June 30, 2016
 
Parent/
Issuer
 
Combined
Guarantor
Subsidiaries
 
Intercompany
Eliminations
 
Consolidated
 
(In thousands)
Cash flows from operating activities:
 
 
 
 
 
 
 
Net loss
$
(154,386
)
 
$
(109,314
)
 
$
109,314

 
$
(154,386
)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
 
 
 
 
 
 
 
Equity in loss of subsidiaries
109,314

 
—

 
(109,314
)
 
—

Depreciation, depletion and amortization
—

 
244,937

 
—

 
244,937

Gain on extinguishment of debt
(18,658
)
 
—

 
—

 
(18,658
)
Loss on sale of properties
—

 
1,311

 
—

 
1,311

Impairment
—

 
3,585

 
—

 
3,585

Deferred income taxes
(18,095
)
 
(62,032
)
 
—

 
(80,127
)
Derivative instruments
—

 
76,471

 
—

 
76,471

Stock-based compensation expenses
12,624

 
355

 
—

 
12,979

Deferred financing costs amortization and other
3,360

 
3,192

 
—

 
6,552

Working capital and other changes:
 
 
 
 
 
 
 
Change in accounts receivable
(85
)
 
53,068

 
(48,686
)
 
4,297

Change in inventory
—

 
2,054

 
—

 
2,054

Change in prepaid expenses
278

 
1,145

 
—

 
1,423

Change in other current assets
—

 
(114
)
 
—

 
(114
)
Change in long-term inventory and other assets
100

 
—

 
—

 
100

Change in accounts payable, interest payable and accrued liabilities
(50,462
)
 
(16,258
)
 
48,686

 
(18,034
)
Change in other current liabilities
—

 
9,001

 
—

 
9,001

Change in other liabilities
—

 
10

 
—

 
10

Net cash provided by (used in) operating activities
(116,010
)
 
207,411

 
—

 
91,401

Cash flows from investing activities:
 
 
 
 
 
 
 
Capital expenditures
—

 
(231,341
)
 
—

 
(231,341
)
Proceeds from sale of properties
—

 
11,679

 
—

 
11,679

Costs related to sale of properties
—

 
(310
)
 
—

 
(310
)
Derivative settlements
—

 
103,790

 
—

 
103,790

Advances from joint interest partners
—

 
769

 
—

 
769

Net cash used in investing activities
—

 
(115,413
)
 
—

 
(115,413
)
Cash flows from financing activities:
 
 
 
 
 
 
 
Proceeds from revolving credit facility
—

 
359,000

 
—

 
359,000

Principal payments on revolving credit facility
—

 
(462,000
)
 
—

 
(462,000
)
Repurchase of senior unsecured notes
(56,925
)
 
—

 
—

 
(56,925
)
Deferred financing costs
—

 
(751
)
 
—

 
(751
)
Proceeds from sale of common stock
182,953

 
—

 
—

 
182,953

Purchases of treasury stock
(1,520
)
 
—

 
—

 
(1,520
)
Investment in / capital contributions from subsidiaries
(9,190
)
 
9,190

 
—

 
—

Net cash provided by (used in) financing activities
115,318

 
(94,561
)
 
—

 
20,757

Decrease in cash and cash equivalents
(692
)
 
(2,563
)
 
—

 
(3,255
)
Cash and cash equivalents at beginning of period
777

 
8,953

 
—

 
9,730

Cash and cash equivalents at end of period
$
85

 
$
6,390

 
$
—

 
$
6,475


25
Table of Contents

15. Subsequent Events
The Company has evaluated the period after the balance sheet date, noting no subsequent events or transactions that required recognition or disclosure in the financial statements, other than as noted below.
Derivative instruments. In July and August 2017, the Company entered into new swaps and two-way costless collar options for crude oil which settle based on WTI. The commodity contracts included a total notional amount of 244,000 barrels with a weighted average floor price of $49.43 per barrel which settle in 2017, 2,915,000 barrels with a weighted average floor price of $48.59 per barrel which settle in 2018, and 248,000 barrels with a weighted average floor price of $48.49 per barrel which settle in 2019. These derivative instruments do not qualify for or were not designated as hedging instruments for accounting purposes.

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Table of Contents

Item 2. — Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” contained in our Annual Report on Form 10-K for the year ended December 31, 2016 (“2016 Annual Report”), as well as the unaudited condensed consolidated financial statements and notes thereto included in this Quarterly Report on Form 10-Q.
CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS
This Quarterly Report on Form 10-Q contains 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”). These forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond our control. All statements, other than statements of historical fact included in this Quarterly Report on Form 10-Q, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this Quarterly Report on Form 10-Q, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “continue,” “predict,” “potential,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. In particular, the factors discussed below and detailed under Part II, Item 1A. “Risk Factors” in our 2016 Annual Report could affect our actual results and cause our actual results to differ materially from expectations, estimates, or assumptions expressed in, forecasted in, or implied in such forward-looking statements.
Forward-looking statements may include statements about:
•
our business strategy;
•
estimated future net reserves and present value thereof;
•
timing and amount of future production of oil and natural gas;
•
drilling and completion of wells;
•
estimated inventory of wells remaining to be drilled and completed;
•
costs of exploiting and developing our properties and conducting other operations;
•
availability of drilling, completion and production equipment and materials;
•
availability of qualified personnel;
•
owning and operating a midstream company;
•
owning and operating a well services company;
•
infrastructure for salt water gathering and disposal;
•
gathering, transportation and marketing of oil and natural gas, both in the Williston Basin and other regions in the United States;
•
property acquisitions, including our recent acquisition of oil and gas properties in the Williston Basin;
•
integration and benefits of property acquisitions or the effects of such acquisitions on our cash position and levels of indebtedness;
•
the amount, nature and timing of capital expenditures;
•
availability and terms of capital;
•
our financial strategy, budget, projections, execution of business plan and operating results;
•
cash flows and liquidity;
•
oil and natural gas realized prices;
•
general economic conditions;
•
operating environment, including inclement weather conditions;
•
effectiveness of risk management activities;
•
competition in the oil and natural gas industry;
•
counterparty credit risk;
•
environmental liabilities;
•
governmental regulation and the taxation of the oil and natural gas industry;

27
Table of Contents

•
developments in oil-producing and natural gas-producing countries;
•
technology;
•
uncertainty regarding future operating results; and
•
plans, objectives, expectations and intentions contained in this report that are not historical.
All forward-looking statements speak only as of the date of this Quarterly Report on Form 10-Q. We disclaim any obligation to update or revise these statements unless required by securities law, and you should not place undue reliance on these forward-looking statements. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this Quarterly Report on Form 10-Q are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved. Some of the key factors which could cause actual results to vary from our expectations include changes in oil and natural gas prices, weather and environmental conditions, the timing of planned capital expenditures, availability of acquisitions, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well as our ability to access them, the proximity to and capacity of transportation facilities, and uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, as well as those factors discussed below and elsewhere in this Quarterly Report on Form 10-Q, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.
Overview
We are an independent exploration and production (“E&P”) company focused on the acquisition and development of unconventional oil and natural gas resources primarily in the North Dakota and Montana regions of the Williston Basin. Since our inception, we have acquired properties that provide current production and significant upside potential through further development. Our drilling activity is primarily directed toward projects that we believe can provide us with repeatable successes in the Bakken and Three Forks formations. Oasis Petroleum North America LLC (“OPNA”) conducts our domestic oil and natural gas E&P activities. We also operate a midstream services business through Oasis Midstream Services LLC (“OMS”) and a well services business through Oasis Well Services LLC (“OWS”), both of which are separate reportable business segments that are complementary to our primary development and production activities. The revenues and expenses related to work performed by OMS and OWS for OPNA’s working interests are eliminated in consolidation and, therefore, do not directly contribute to our consolidated results of operations.
Our use of capital for acquisitions and development allows us to direct our capital resources to what we believe to be the most attractive opportunities as market conditions evolve. We have historically acquired properties that we believe will meet or exceed our rate of return criteria. We built our Williston Basin assets through acquisitions and development activities, which were financed with a combination of capital from private investors, borrowings under our revolving credit facility, cash flows provided by operating activities, proceeds from our senior unsecured notes, proceeds from our public equity offerings, the sale of certain non-core oil and gas properties and cash settlements of derivative contracts. For acquisitions of properties with additional development, exploitation and exploration potential, we have focused on acquiring properties that we expect to operate so that we can control the timing and implementation of capital spending. In some instances, we have acquired non-operated property interests at what we believe to be attractive rates of return either because they provided an entry into a new area of interest or complemented our existing operations. In addition, the acquisition of non-operated properties in new areas provides us with geophysical and geologic data that may lead to further acquisitions in the same area, whether on an operated or non-operated basis. We intend to continue to acquire both operated and non-operated properties to the extent we believe they meet our return objectives.
Due to the geographic concentration of our oil and natural gas properties in the Williston Basin, we believe the primary sources of opportunities, challenges and risks related to our business for both the short and long-term are:
•
commodity prices for oil and natural gas;
•
transportation capacity;
•
availability and cost of services; and
•
availability of qualified personnel.
Our revenue, profitability and future growth rate depend substantially on factors beyond our control, such as economic, political and regulatory developments as well as competition from other sources of energy. Prices for oil and natural gas can fluctuate widely in response to relatively minor changes in the global and regional supply of and demand for oil and natural gas, as well as market uncertainty, economic conditions and a variety of additional factors. Since the inception of our oil and natural gas activities, commodity prices have experienced significant fluctuations, and may fluctuate widely in the future.

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Table of Contents

Extended periods of low prices for oil or natural gas could materially and adversely affect our financial position, our results of operations, the quantities of oil and natural gas reserves that we can economically produce and our access to capital.
In an effort to improve price realizations from the sale of our oil and natural gas, we manage our commodities marketing activities in-house, which enables us to market and sell our oil and natural gas to a broader array of potential purchasers. We enter into crude oil and natural gas sales contracts with purchasers who have access to transportation capacity, utilize derivative financial instruments to manage our commodity price risk and enter into physical delivery contracts to manage our price differentials. Due to the availability of other markets and pipeline connections, we do not believe that the loss of any single oil or natural gas customer would have a material adverse effect on our results of operations or cash flows. Additionally, we sell a significant amount of our crude oil production through gathering systems connected to multiple pipeline and rail facilities. These gathering systems, which originate at the wellhead, reduce the need to transport barrels by truck from the wellhead. Currently, 90% of our gross operated oil production and substantially all of our gross operated natural gas production are connected to these gathering systems, and our crude oil price differentials have improved to less than $3.00 per barrel primarily due to the additional takeaway capacity of the Dakota Access Pipeline of over 450,000 barrels per day.
Highlights:
•
We produced 61,943 barrels of oil equivalent per day (“Boepd”) in the second quarter of 2017;
•
We completed and placed on production 15 gross (10.8 net) operated wells in the Williston Basin in the second quarter of 2017 and ended the quarter with 81 gross operated wells waiting on completion;
•
Total capital expenditures were $173.0 million and $282.8 million for the three and six months ended June 30, 2017, respectively;
•
At June 30, 2017, we had $11.4 million of cash and cash equivalents and had total liquidity of $733.4 million, including the availability under our revolving credit facility;
•
Net cash provided by operating activities was $102.1 million for the three months ended June 30, 2017. Adjusted EBITDA, a non-GAAP financial measure, was $141.3 million for the three months ended June 30, 2017. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to net income and net cash provided by operating activities, see “Non-GAAP Financial Measures” below.
Results of Operations
Revenues
Our oil and gas revenues are derived from the sale of oil and natural gas production. These revenues do not include the effects of derivative instruments and may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices. Our bulk oil sales are derived from the sale of oil purchased through our marketing activities primarily for blending. Our midstream revenues are primarily derived from salt water pipeline transport, salt water disposal, natural gas gathering and processing, fresh water sales and crude oil gathering and transportation. Our well services revenues are derived from well services, product sales and equipment rentals. Substantially all of our midstream revenues and well services revenues are from services for third-party working interest owners in OPNA’s operated wells. Intercompany revenues for work performed by OMS and OWS for OPNA’s working interests are eliminated in consolidation and are therefore not included in midstream and well services revenues.

29
Table of Contents

The following table summarizes our revenues and production data for the periods presented:
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2017
 
2016
 
Change
 
2017
 
2016
 
Change
Operating results (in thousands):
 
 
 
 
 
 
 
 
 
 
 
Revenues
 
 
 
 
 
 
 
 
 
 
 
Oil
$
194,005

 
$
152,900

 
$
41,105

 
$
402,599

 
$
264,106

 
$
138,493

Natural gas
24,628

 
6,437

 
18,191

 
53,286

 
12,546

 
40,740

Bulk oil sales
8,091

 
—

 
8,091

 
35,722

 
—

 
35,722

Midstream
15,566

 
6,910

 
8,656

 
30,172

 
13,893

 
16,279

Well services
11,801

 
12,833

 
(1,032
)
 
17,428

 
18,818

 
(1,390
)
Total revenues
$
254,091

 
$
179,080

 
$
75,011

 
$
539,207

 
$
309,363

 
$
229,844

Production data:
 
 
 
 
 
 
 
 
 
 
 
Oil (MBbls)
4,349

 
3,747

 
602

 
8,785

 
7,617

 
1,168

Natural gas (MMcf)
7,725

 
4,549

 
3,176

 
15,237

 
8,802

 
6,435

Oil equivalents (MBoe)
5,637

 
4,505

 
1,132

 
11,324

 
9,084

 
2,240

Average daily production (Boe per day)
61,943

 
49,507

 
12,436

 
62,564

 
49,911

 
12,653

Average sales prices:

 

 
 
 
 
 
 
 
 
Oil, without derivative settlements (per Bbl)
$
44.61

 
$
40.81

 
$
3.80

 
$
45.83

 
$
34.67

 
$
11.16

Oil, with derivative settlements (per Bbl)(1)
42.56

 
48.94

 
(6.38
)
 
40.72

 
48.30

 
(7.58
)
Natural gas (per Mcf)(2)
3.19

 
1.42

 
1.77

 
3.50

 
1.43

 
2.07

____________________
(1)
Realized prices include gains or losses on cash settlements for commodity derivatives, which do not qualify for or were not designated as hedging instruments for accounting purposes. Cash settlements represent the cumulative gains and losses on our derivative instruments for the periods presented and do not include a recovery of costs that were paid to acquire or modify the derivative instruments that were settled.
(2)
Natural gas prices include the value for natural gas and natural gas liquids.
Three months ended June 30, 2017 as compared to three months ended June 30, 2016
Oil and gas revenues. Our oil and gas revenues increased $59.3 million, or 37%, to $218.6 million during the three months ended June 30, 2017 as compared to the three months ended June 30, 2016. The higher oil and natural gas production amounts sold increased revenues by $37.0 million coupled with a $22.3 million increase due to higher oil and natural gas sales prices during the three months ended June 30, 2017 as compared to the three months ended June 30, 2016. Average oil sales prices, without derivative settlements, increased by $3.80 per barrel to an average of $44.61 per barrel, and average natural gas sales prices, which includes the value for natural gas and natural gas liquids, increased by $1.77 per Mcf to an average of $3.19 per Mcf for the three months ended June 30, 2017 as compared to the three months ended June 30, 2016. Average daily production sold increased by 12,436 Boe per day to 61,943 Boe per day during the three months ended June 30, 2017 as compared to the three months ended June 30, 2016. The increase in average daily production sold was primarily a result of our acquisition completed on December 1, 2016 of approximately 55,000 net acres in the Williston Basin (the “Williston Basin Acquisition”).
Bulk oil sales. During the three months ended June 30, 2017, bulk oil sales were $8.1 million, which represents the sale of crude oil purchased primarily for blending at our crude oil terminal that began in late 2016. There were no bulk oil sales during the three months ended June 30, 2016.
Midstream revenues. Midstream revenues increased $8.7 million to $15.6 million during the three months ended June 30, 2017 as compared to the three months ended June 30, 2016. This increase was driven by a $7.3 million increase primarily related to higher natural gas volumes gathered, compressed and processed coupled with a $2.2 million increase related to higher oil volumes gathered, stabilized and transported as a result of the start up of our natural gas processing plant and our oil gathering system in the second half of 2016, respectively. These increases were offset by a decrease of $0.6 million related to lower salt water disposal revenues.
Well services revenues. Our well services revenues decreased by 8% to $11.8 million for the three months ended June 30, 2017 as compared to the three months ended June 30, 2016, primarily due to OWS completing OPNA wells with a lower average third-party working interest during the three months ended June 30, 2017, offset by an increase in well completion product sales.

30
Table of Contents

Six months ended June 30, 2017 as compared to six months ended June 30, 2016
Oil and gas revenues. Our oil and gas revenues increased $179.2 million, or 65%, to $455.9 million during the six months ended June 30, 2017 as compared to the six months ended June 30, 2016. The higher oil and natural gas sales prices increased revenues by $103.2 million coupled with a $76.0 million increase due to higher oil and natural gas production amounts sold during the six months ended June 30, 2017 as compared to the six months ended June 30, 2016. Average oil sales prices, without derivative settlements, increased by $11.16 per barrel to an average of $45.83 per barrel, and average natural gas sales prices, which include the value for natural gas and natural gas liquids, increased by $2.07 per Mcf to an average of $3.50 per Mcf for the six months ended June 30, 2017 as compared to the six months ended June 30, 2016. Average daily production sold increased by 12,653 Boe per day to 62,564 Boe per day during the six months ended June 30, 2017 as compared to the six months ended June 30, 2016. The increase in average daily production sold was primarily a result of the Williston Basin Acquisition completed on December 1, 2016 of approximately 55,000 net acres.
Bulk oil sales. During the six months ended June 30, 2017, bulk oil sales were $35.7 million, which represents the sale of crude oil purchased primarily for blending at our crude oil terminal that began in late 2016. There were no bulk oil sales during the six months ended June 30, 2016.
Midstream revenues. Midstream revenues increased $16.3 million to $30.2 million during the six months ended June 30, 2017 as compared to the six months ended June 30, 2016. This increase was driven by a $13.6 million increase primarily related to higher natural gas volumes gathered, compressed and processed coupled with a $4.4 million increase related to higher oil volumes gathered, stabilized and transported as a result of the start up of our natural gas processing plant and our oil gathering system in the second half of 2016, respectively. These increases were offset by a decrease of $1.0 million related to salt water disposal revenues coupled with a $0.8 million decrease related to lower freshwater sales.
Well services revenues. In response to the low commodity price environment, we decreased the pace of our well completions and reduced OWS to one fracturing fleet during the first quarter of 2016. Our well services revenues decreased by 7% to $17.4 million for the six months ended June 30, 2017 as compared to the six months ended June 30, 2016, primarily due to a decrease in well completion activity, offset by an increase in well completion product sales.

31
Table of Contents

Expenses and other income
The following table summarizes our operating expenses and other income and expenses for the periods presented:
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2017
 
2016
 
Change
 
2017
 
2016
 
Change
 
(In thousands, except per Boe of production)
Operating expenses:
 
 
 
 
 
 
 
 
 
 
 
Lease operating expenses
$
44,665

 
$
31,523

 
$
13,142

 
$
88,537

 
$
62,587

 
$
25,950

Midstream operating expenses
3,263

 
1,740

 
1,523

 
6,590

 
3,478

 
3,112

Well services operating expenses
8,088

 
7,135

 
953

 
11,990

 
9,786

 
2,204

Marketing, transportation and gathering expenses
12,039

 
6,491

 
5,548

 
22,990

 
15,043

 
7,947

Bulk oil purchases
7,980

 
—

 
7,980

 
35,982

 
—

 
35,982

Production taxes
18,971

 
14,367

 
4,604

 
39,270

 
25,120

 
14,150

Depreciation, depletion and amortization
125,291

 
122,488

 
2,803

 
251,957

 
244,937

 
7,020

Exploration expenses
1,667

 
340

 
1,327

 
3,156

 
703

 
2,453

Impairment
3,200

 
23

 
3,177

 
5,882

 
3,585

 
2,297

General and administrative expenses
23,548

 
21,876

 
1,672

 
47,382

 
46,242

 
1,140

Total operating expenses
248,712

 
205,983

 
42,729

 
513,736

 
411,481

 
102,255

Loss on sale of properties
—

 
(1,311
)
 
1,311

 
—

 
(1,311
)
 
1,311

Operating income (loss)
5,379

 
(28,214
)
 
33,593

 
25,471

 
(103,429
)
 
128,900

Other income (expense)
 
 
 
 
 
 
 
 
 
 
 
Net gain (loss) on derivative instruments
50,532

 
(90,846
)
 
141,378

 
106,607

 
(76,471
)
 
183,078

Interest expense, net of capitalized interest
(36,838
)
 
(34,979
)
 
(1,859
)
 
(73,159
)
 
(73,718
)
 
559

Gain on extinguishment of debt
—

 
11,642

 
(11,642
)
 
—

 
18,658

 
(18,658
)
Other income (expense)
(166
)
 
(32
)
 
(134
)
 
(150
)
 
447

 
(597
)
Total other income (expense)
13,528

 
(114,215
)
 
127,743

 
33,298

 
(131,084
)
 
164,382

Income (loss) before income taxes
18,907

 
(142,429
)
 
161,336

 
58,769

 
(234,513
)
 
293,282

Income tax benefit (expense)
(2,339
)
 
52,498

 
(54,837
)
 
(18,376
)
 
80,127

 
(98,503
)
Net income (loss)
$
16,568

 
$
(89,931
)
 
$
106,499

 
$
40,393

 
$
(154,386
)
 
$
194,779

Costs and expenses (per Boe of production):
 
 
 
 
 
 
 
 
 
 
 
Lease operating expenses
$
7.92

 
$
7.00

 
$
0.92

 
$
7.82

 
$
6.89

 
$
0.93

Marketing, transportation and gathering expenses
2.14

 
1.44

 
0.70

 
2.03

 
1.66

 
0.37

Production taxes
3.37

 
3.19

 
0.18

 
3.47

 
2.77

 
0.70

Depreciation, depletion and amortization
22.23

 
27.19

 
(4.96
)
 
22.25

 
26.96

 
(4.71
)
General and administrative expenses
4.18

 
4.86

 
(0.68
)
 
4.18

 
5.09

 
(0.91
)
Three months ended June 30, 2017 as compared to three months ended June 30, 2016
Lease operating expenses. Lease operating expenses increased $13.1 million to $44.7 million for the three months ended June 30, 2017 as compared to the three months ended June 30, 2016. The increase was primarily due to higher costs associated with operating an increased number of producing wells as a result of our well completions and the Williston Basin Acquisition coupled with an increase in workover costs during the three months ended June 30, 2017. Lease operating expenses increased from $7.00 per Boe for the three months ended June 30, 2016 to $7.92 per Boe for the three months ended June 30, 2017 primarily due to the higher aforementioned costs.
Midstream operating expenses. Midstream operating expenses represent operating expenses incurred by OMS associated with volumes for third-party working interest owners. The $1.5 million increase for the three months ended June 30, 2017 as compared to the three months ended June 30, 2016 was primarily related to the start up of our natural gas processing plant and our oil gathering system during 2016, partially offset by a decrease in salt water disposal expenses.
Well services operating expenses. Well services operating expenses represent operating expenses incurred by OWS for third-party working interest owners’ share of completion services. The $1.0 million increase for the three months ended June 30, 2017 as compared to the three months ended June 30, 2016 was primarily attributable to well completion product sales, offset by lower well completion activity and decreased maintenance and trucking costs.
Marketing, transportation and gathering expenses. Marketing, transportation and gathering expenses increased $5.5 million, or $0.70 per Boe, for the three months ended June 30, 2017 as compared to the three months ended June 30, 2016,

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which was primarily attributable to higher oil gathering and transportation expenses related to additional well connections on OMS infrastructure and the start up of our natural gas processing plant and our oil gathering system, respectively, in the second half of 2016 coupled with the start up of the Dakota Access Pipeline during the three months ended June 30, 2017. Excluding non-cash valuation adjustments, our marketing, transportation and gathering expenses on a per Boe basis increased to $2.17 during the three months ended June 30, 2017 as compared to $1.55 during the three months ended June 30, 2016.
Bulk oil purchases. For the three months ended June 30, 2017, we incurred $8.0 million of bulk oil purchase costs primarily related to blending. We did not incur similar charges during the three months ended June 30, 2016.
Production taxes. Our production taxes as a percentage of oil and natural gas sales were 8.7% and 9.0% for the three months ended June 30, 2017 and 2016, respectively. The production tax rate decreased period over period primarily due to a lower oil production mix. North Dakota’s natural gas production tax is $0.0601 per Mcf.
Depreciation, depletion and amortization (“DD&A”). DD&A expense increased $2.8 million to $125.3 million for the three months ended June 30, 2017 as compared to the three months ended June 30, 2016. This increase in DD&A expense for the three months ended June 30, 2017 was a result of production increases from our wells completed during the three months ended June 30, 2017 coupled with the Williston Basin Acquisition, offset by a decrease in the DD&A rate to $22.23 per Boe for the three months ended June 30, 2017 as compared to $27.19 per Boe for the three months ended June 30, 2016. The decrease in the DD&A rate was primarily due to lower well costs and higher recoverable reserves.
Impairment. As a result of periodic assessments of our unproved properties not held-by-production, we recorded an impairment loss on our unproved oil and natural gas properties of $3.2 million for the three months ended June 30, 2017 related to acreage expiring in future periods because there were no current plans to drill or extend the leases prior to their expiration. For the three months ended June 30, 2016, we recorded an impairment loss on our unproved oil and natural gas properties of $23,000 due to leases that expired in the period. No impairment charges of proved oil and gas or other properties were recorded for the three months ended June 30, 2017 and 2016.
General and administrative expenses (“G&A”). Our G&A increased $1.7 million to $23.5 million for the three months ended June 30, 2017 as compared to the three months ended June 30, 2016. E&P and OMS G&A increased $2.1 million and $1.0 million, respectively, for the three months ended June 30, 2017 as compared to the three months ended June 30, 2016. The increase in E&P and OMS was primarily due to increased employee compensation expenses as a result of organizational growth due to increased activity and the start up of our natural gas processing plant in the third quarter of 2016. OWS G&A decreased $1.4 million for the three months ended June 30, 2017 as compared to the three months ended June 30, 2016 primarily due to OWS completing OPNA wells with a lower average third-party working interest and decreased employee compensation and rental expenses.
Derivative instruments. As a result of entering into derivative contracts and the effect of the forward strip oil changes, we incurred a $50.5 million net gain on derivative instruments, including net cash settlement payments of $0.9 million, for the three months ended June 30, 2017, and a $90.8 million net loss on derivative instruments, including net cash settlement receipts of $30.5 million for the three months ended June 30, 2016. Cash settlements represent the cumulative gains and losses on our derivative instruments for the periods presented and do not include recovery of costs that were paid to acquire or modify the derivative instruments that were settled.
Interest expense. Interest expense increased $1.8 million from $35.0 million for the three months ended June 30, 2016 to $36.8 million for the three months ended June 30, 2017 primarily due to interest expense related to our senior unsecured convertible notes issued in September 2016, which includes debt discount amortization, and our revolving credit facility coupled with a decrease in capitalized interest due to lower costs for work in progress assets as a result of the completion of our natural gas processing plant in the third quarter of 2016. This increase was offset by the repurchase of an aggregate principal amount of $447.0 million of outstanding senior unsecured notes in 2016, which resulted in a $7.0 million decrease in interest costs.  For the three months ended June 30, 2017 and 2016, the weighted average debt outstanding under our revolving credit facility was $422.1 million and $82.7 million, respectively. The weighted average interest rate incurred on the outstanding borrowings under our revolving credit facility was 2.8% and 2.0% for the three months ended June 30, 2017 and 2016, respectively. Interest capitalized during the three months ended June 30, 2017 and 2016 was $2.8 million and $4.8 million, respectively.
Gain on extinguishment of debt. For the three months ended June 30, 2017, we did not repurchase any portion of our outstanding senior unsecured notes. During the three months ended June 30, 2016, we repurchased an aggregate principal amount of $46.8 million of our outstanding senior unsecured notes for an aggregate cost of $34.6 million, including accrued interest and fees. For the three months ended June 30, 2016, we recognized a pre-tax gain related to the repurchase of $11.6 million, which included unamortized deferred financing costs write-offs of $0.5 million.
Income taxes. The income tax expense for the three months ended June 30, 2017 was recorded at 12.4% of pre-tax income, and the income tax benefit for the three months ended June 30, 2016 was recorded at 36.9% of pre-tax loss. The effective tax rate for the three months ended June 30, 2017 was lower than the combined federal statutory rate and the statutory

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rates for the states in which we conduct business due to the impact of permanent differences and a forecasted annual pre-tax loss for 2017, while the effective tax rate for the three months ended June 30, 2016 was lower than the combined federal statutory rate and the statutory rates for the states in which we conduct business due to the impact of permanent differences on pre-tax loss for the period. The permanent differences were primarily between amounts expensed for book purposes versus the amounts deductible for income tax purposes related to compensation.
Six months ended June 30, 2017 as compared to six months ended June 30, 2016
Lease operating expenses. Lease operating expenses increased $26.0 million to $88.5 million for the six months ended June 30, 2017 as compared to the six months ended June 30, 2016. The increase was primarily due to higher costs associated with operating an increased number of producing wells as a result of our well completions and the Williston Basin Acquisition coupled with an increase in workover costs during the six months ended June 30, 2017. Lease operating expenses increased from $6.89 per Boe for the six months ended June 30, 2016 to $7.82 per Boe for the six months ended June 30, 2017 primarily due to the higher aforementioned costs.
Midstream operating expenses. Midstream operating expenses represent operating expenses incurred by OMS associated with volumes for third-party working interest owners. The $3.1 million increase for the six months ended June 30, 2017 as compared to the six months ended June 30, 2016 was primarily related to the start up of our natural gas processing plant and our oil gathering system during 2016, partially offset by a decrease in fresh water purchases.
Well services operating expenses. Well services operating expenses represent operating expenses incurred by OWS for third-party working interest owners’ share of completion services. The $2.2 million increase for the six months ended June 30, 2017 as compared to the six months ended June 30, 2016 was primarily attributable to increased well completion product sales coupled with increased maintenance and trucking costs, offset by lower well completion activity.
Marketing, transportation and gathering expenses. Marketing, transportation and gathering expenses increased $7.9 million, or $0.37 per Boe, for the six months ended June 30, 2017 as compared to the six months ended June 30, 2016, which was primarily attributable to an increase in natural gas gathering and processing expenses coupled with higher oil gathering and transportation expenses related to additional well connections on OMS infrastructure and the start up of our natural gas processing plant and our oil gathering system, respectively, in the second half of 2016. Excluding non-cash valuation adjustments, our marketing, transportation and gathering expenses on a per Boe basis increased to $1.97 during the six months ended June 30, 2017 as compared to $1.58 during the six months ended June 30, 2016.
Bulk oil purchases. For the six months ended June 30, 2017, we incurred $36.0 million of bulk oil purchase costs primarily related to blending. We did not incur similar charges during the six months ended June 30, 2016.
Production taxes. Our production taxes as a percentage of oil and natural gas sales were 8.6% and 9.1% for the six months ended June 30, 2017 and 2016, respectively. The production tax rate decreased period over period primarily due to a lower oil production mix. North Dakota’s natural gas production tax is $0.0601 per Mcf.
Depreciation, depletion and amortization. DD&A expense increased $7.0 million to $252.0 million for the six months ended June 30, 2017 as compared to the six months ended June 30, 2016. This increase in DD&A expense for the six months ended June 30, 2017 was a result of production increases from our wells completed during the six months ended June 30, 2017 coupled with the Williston Basin Acquisition, offset by a decrease in the DD&A rate to $22.25 per Boe for the six months ended June 30, 2017 as compared to $26.96 per Boe for the six months ended June 30, 2016. The decrease in the DD&A rate was primarily due to lower well costs and higher recoverable reserves.
Impairment. As a result of periodic assessments of our unproved properties not held-by-production, we recorded an impairment loss on our unproved oil and natural gas properties of $5.9 million for the six months ended June 30, 2017 related to acreage expiring in future periods because there were no current plans to drill or extend the leases prior to their expiration. For the six months ended June 30, 2016, we recorded an impairment loss of $3.6 million to further adjust the carrying value of our properties held for sale to their estimated fair value, determined based on the expected sales price, less costs to sell. No impairment charges of proved oil and gas or other properties were recorded for the six months ended June 30, 2017.
General and administrative expenses. Our G&A increased $1.1 million to $47.4 million for the six months ended June 30, 2017 as compared to the six months ended June 30, 2016. E&P G&A was $40.0 million and $38.8 million for the six months ended June 30, 2017 and 2016, respectively. The $1.1 million increase in E&P G&A was primarily due to increased compensation expenses due to an increase in employee headcount, partially offset by severance expenses during the first quarter of 2016. OMS G&A increased $1.7 million for the six months ended June 30, 2017 as compared to the six months ended June 30, 2016 primarily due to increased employee compensation as a result of organizational growth within this segment due to the start up of our natural gas processing plant in the third quarter of 2016. OWS G&A decreased $1.7 million for the six months ended June 30, 2017 as compared to the six months ended June 30, 2016 primarily due to lower compensation expenses due to severance expenses paid in 2016.

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Derivative instruments. As a result of entering into derivative contracts and the effect of the forward strip oil price changes, we incurred a $106.6 million net gain on derivative instruments, including net cash settlement payments of $8.9 million, for the six months ended June 30, 2017, and a $76.5 million net loss on derivative instruments, including net cash settlement receipts of $103.8 million, for the six months ended June 30, 2016. Cash settlements represent the cumulative gains and losses on our derivative instruments for the periods presented and do not include recovery of costs that were paid to acquire or modify the derivative instruments that were settled.
Interest expense. Interest expense decreased $0.5 million from $73.7 million for the six months ended June 30, 2016 to $73.2 million for the six months ended June 30, 2017 primarily due to the repurchase of an aggregate principal amount of $447.0 million of outstanding senior unsecured notes in 2016, which resulted in a $15.1 million decrease in interest costs. This decrease was offset by interest expense related to our senior unsecured convertible notes issued in September 2016, which includes debt discount amortization, and our revolving credit facility coupled with a decrease in capitalized interest due to lower costs for work in progress assets as a result of the completion of our natural gas processing plant in the third quarter of 2016. For the six months ended June 30, 2017 and 2016, the weighted average debt outstanding under our revolving credit facility was $411.5 million and $94.8 million, respectively. The weighted average interest rate incurred on the outstanding borrowings under our revolving credit facility was 2.7% and 1.9% for the six months ended June 30, 2017 and 2016, respectively. Interest capitalized during the six months ended June 30, 2017 and 2016 was $5.6 million and $9.3 million, respectively.
Gain on extinguishment of debt. For the six months ended June 30, 2017, we did not repurchase any portion of our outstanding senior unsecured notes. During the six months ended June 30, 2016, we repurchased an aggregate principal amount of $76.6 million of our outstanding senior unsecured notes for an aggregate cost of $56.9 million, including accrued interest and fees. For the six months ended June 30, 2016, we recognized a pre-tax gain related to the repurchase of $18.7 million, which included unamortized deferred financing costs write-offs of $1.0 million.
Income taxes. The income tax expense for the six months ended June 30, 2017 was recorded at 31.3% of pre-tax income, and the income tax benefit for the six months ended June 30, 2016 was recorded at 34.2% of pre-tax loss. The effective tax rate for the six months ended June 30, 2017 was lower than the combined federal statutory rate and the statutory rates for the states in which we conduct business due to the impact of permanent differences and a forecasted annual pre-tax loss for 2017, while the effective tax rate for the six months ended June 30, 2016 was lower than the combined federal statutory rate and the statutory rates for the states in which we conduct business due to the impact of permanent differences on pre-tax loss for the period. The permanent differences were primarily between amounts expensed for book purposes versus the amounts deductible for income tax purposes related to compensation.
Liquidity and Capital Resources
Our primary sources of liquidity as of the date of this report have been proceeds from our senior unsecured notes, borrowings under our revolving credit facility, proceeds from public equity offerings, cash flows from operations, the sale of certain non-core oil and gas properties and cash settlements of derivative contracts. Our primary uses of capital have been for the acquisition and development of oil and natural gas properties and midstream infrastructure, payment of operating and general and administrative costs, interest payments on outstanding debt and repurchases of our senior unsecured notes. We continually monitor potential capital sources, including equity and debt financings and potential asset monetizations, in order to enhance liquidity and decrease leverage. Our future success in growing proved reserves and production will be highly dependent on our ability to access outside sources of capital.
Our cash flows for the six months ended June 30, 2017 and 2016 are presented below:
 
Six Months Ended June 30,
 
2017
 
2016
 
(In thousands)
Net cash provided by operating activities
$
209,861

 
$
91,401

Net cash used in investing activities
(259,141
)
 
(115,413
)
Net cash provided by financing activities
49,494

 
20,757

Increase (decrease) in cash and cash equivalents
$
214

 
$
(3,255
)
Our cash flows depend on many factors, including the price of oil and natural gas and the success of our development and exploration activities as well as future acquisitions. We actively manage our exposure to commodity price fluctuations by executing derivative transactions to mitigate the change in oil and natural gas prices on a portion of our production, thereby mitigating our exposure to oil and natural gas price declines, but these transactions may also limit our cash flow in periods of rising oil and natural gas prices. For additional information on the impact of changing prices on our financial position, see Item 3. “Quantitative and Qualitative Disclosures About Market Risk” below.

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Cash flows provided by operating activities
Net cash provided by operating activities was $209.9 million and $91.4 million for the six months ended June 30, 2017 and 2016, respectively. The change in cash flows from operating activities for the period ended June 30, 2017 as compared to 2016 was primarily the result of higher realized oil and natural gas sales prices.
Working capital. Our working capital fluctuates primarily as a result of changes in commodity pricing and production volumes, capital spending to fund our exploratory and development initiatives and acquisitions, and the impact of our outstanding derivative instruments. We had a working capital deficit of $50.5 million at June 30, 2017 primarily due to increases in our current liabilities, including accrued liabilities for drilling and development costs. As of June 30, 2017, we had $733.4 million of liquidity available, including $11.4 million in cash and cash equivalents and $722.0 million of unused borrowing base committed capacity available under our revolving credit facility. At June 30, 2016, we had a working capital deficit of $139.8 million.
Cash flows used in investing activities
Net cash used in investing activities was $259.1 million and $115.4 million during the six months ended June 30, 2017 and 2016, respectively. Net cash used in investing activities during the six months ended June 30, 2017 was primarily attributable to $252.5 million in capital expenditures primarily for drilling and development costs. Net cash used in investing activities during the six months ended June 30, 2016 was primarily attributable to $231.3 million in capital expenditures primarily for drilling and development costs, partially offset by $103.8 million of derivative settlements received as a result of lower commodity prices.
Our capital expenditures are summarized in the following table:
 
Six Months Ended June 30, 2017
 
(In thousands)
Capital expenditures:
 
E&P
$
191,602

OMS
66,921

OWS
268

Other capital expenditures(1)
23,979

Total capital expenditures(2)
$
282,770

___________________
(1)
Other capital expenditures include asset acquisitions, primarily related to midstream assets, of $17.2 million and other items, such as administrative capital and capitalized interest. See Note 6 to our unaudited condensed consolidated financial statements for a description of our midstream assets acquisition.
(2)
Capital expenditures reflected in the table above differ from the amounts shown in the statement of cash flows in our condensed consolidated financial statements because amounts reflected in the table above include changes in accrued liabilities from the previous reporting period for capital expenditures, while the amounts presented in the statement of cash flows are presented on a cash basis.
Our total 2017 capital expenditure budget is $605.0 million, which includes $410.0 million of drilling and completion capital expenditures (including expected savings from services provided by OMS and OWS), $110.0 million for midstream infrastructure and $85.0 million of other capital expenditures, including other E&P capital, capitalized interest, OWS and administrative capital.
While we have budgeted $605.0 million for these purposes, the ultimate amount of capital we will expend may fluctuate materially based on market conditions and the success of our drilling and operations results as the year progresses. Furthermore, if we acquire additional acreage, our capital expenditures may be higher than budgeted. We believe that cash on hand, including cash flows from operating activities and availability under our revolving credit facility should be sufficient to fund our 2017 capital expenditure budget and to meet our future obligations. However, because the operated wells funded by our 2017 drilling plan represent only a small percentage of our potential drilling locations, we will be required to generate or raise multiples of this amount of capital to develop our entire inventory of potential drilling locations should we elect to do so.
Our capital budget may further be adjusted as business conditions warrant. The amount, timing and allocation of capital expenditures is largely discretionary and within our control. If oil prices decline for an extended period of time, we could defer a significant portion of our budgeted capital expenditures until later periods to prioritize capital projects that we believe have the highest expected returns and potential to generate near-term cash flows. We routinely monitor and adjust our capital expenditures in response to changes in prices, availability of financing, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, success or lack of success in drilling activities, contractual obligations, internally generated cash flows and other factors both within and outside our control. We actively review acquisition

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opportunities on an ongoing basis. Our ability to make significant acquisitions for cash would require us to obtain additional equity or debt financing, which we may not be able to obtain on terms acceptable to us or at all.
Cash flows provided by financing activities
Net cash provided by financing activities was $49.5 million and $20.8 million for the six months ended June 30, 2017 and 2016, respectively. For the six months ended June 30, 2017, cash provided by financing activities was primarily due to proceeds from the borrowings under our revolving credit facility, partially offset by principal payments on our revolving credit facility coupled with purchases of treasury stock for shares that employees surrendered back to us to pay tax withholdings upon the vesting of restricted stock awards. Net cash provided by financing activities during the six months ended June 30, 2016 was primarily due to proceeds from borrowings under our revolving credit facility and net proceeds from the issuance of our common stock, partially offset by principal payments on our revolving credit facility and the repurchase of a portion of our outstanding senior unsecured notes.
Senior secured revolving line of credit. We have a revolving credit facility (the “Credit Facility”) with an overall senior secured line of credit of $2,500.0 million as of June 30, 2017. The Credit Facility is restricted to the borrowing base, which is reserve-based and subject to semi-annual redeterminations on April 1 and October 1 of each year. The maturity date of the Credit Facility is April 13, 2020, provided that the 7.25% senior unsecured notes due February 2019 (the “2019 Notes”) are retired or refinanced 90 days prior to their maturity date. On April 10, 2017, the lenders under the Credit Facility (the “Lenders”) completed their regular semi-annual redetermination of the borrowing base scheduled for April 1, 2017, resulting in an increase in the borrowing base from $1,150.0 million to $1,600.0 million; however, we elected to limit the Lenders’ aggregate commitment to $1,150.0 million. The next redetermination of the borrowing base is scheduled for October 1, 2017.
At June 30, 2017, we had $418.0 million of borrowings at a weighted average interest rate of 3.0% and $10.0 million of outstanding letters of credit issued under the Credit Facility, resulting in an unused borrowing base committed capacity of $722.0 million.
The Credit Facility contains covenants that include, among others:
•
a prohibition against incurring debt, subject to permitted exceptions;
•
a prohibition against making dividends, distributions and redemptions, subject to permitted exceptions;
•
a prohibition against making investments, loans and advances, subject to permitted exceptions;
•
restrictions on creating liens and leases on our assets and our subsidiaries, subject to permitted exceptions;
•
restrictions on merging and selling assets outside the ordinary course of business;
•
restrictions on use of proceeds, investments, transactions with affiliates or change of principal business;
•
a provision limiting oil and natural gas derivative financial instruments;
•
a requirement that we maintain a ratio of consolidated EBITDAX (as defined in the Credit Facility) to consolidated Interest Expense (as defined in the Credit Facility) of no less than 2.5 to 1.0 for the four quarters ended on the last day of each quarter; and
•
a requirement that we maintain a Current Ratio (as defined in the Credit Facility) of consolidated current assets (including unused borrowing base committed capacity and with exclusions as described in the Credit Facility) to consolidated current liabilities (with exclusions as described in the Credit Facility) of no less than 1.0 to 1.0 as of the last day of any fiscal quarter.
The Credit Facility contains customary events of default. If an event of default occurs and is continuing, the Lenders may declare all amounts outstanding under the Credit Facility to be immediately due and payable. We were in compliance with the financial covenants of the Credit Facility at June 30, 2017. At June 30, 2017, our consolidated EBITDAX was $527.2 million and our consolidated Interest Expense was $138.2 million, resulting in a ratio of 3.8 as compared to a minimum required ratio of 2.5. In addition, as of June 30, 2017, our consolidated current assets and consolidated current liabilities (as described above) were $980.4 million and $340.7 million, respectively, resulting in a Current Ratio of 2.9 as compared to a minimum required ratio of 1.0. Given the possible fluctuation in commodity prices, we continue to closely monitor our financial covenants and do not anticipate a covenant violation in the next twelve months.
Senior unsecured notes. At June 30, 2017, our long-term debt includes outstanding obligations of $1,753.0 million for senior unsecured notes (the “Senior Notes”), including $54.3 million of the 2019 Notes, $395.5 million of the 6.5% senior unsecured notes due November 2021 (the “2021 Notes”), $937.1 million of the 6.875% senior unsecured notes due March 2022 (the “2022 Notes”) and $366.1 million of the 6.875% senior unsecured notes due January 2023 (the “2023 Notes”).
Prior to certain dates, we have the option to redeem some or all of the Senior Notes for cash at certain redemption prices equal to a certain percentage of their principal amount plus an applicable make-whole premium and accrued and unpaid interest to the redemption date. The 2019 Notes are currently redeemable for cash at a redemption price equal to par plus accrued and

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unpaid interest to the redemption date. We may from time to time seek to retire or purchase our outstanding Senior Notes through cash purchases and/or exchanges for other debt or equity securities, in open market purchases, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.
The indentures governing the Senior Notes restrict our ability and the ability of certain of our subsidiaries to: (i) incur additional debt or enter into sale and leaseback transactions; (ii) pay distributions on, redeem or repurchase equity interests; (iii) make certain investments; (iv) incur liens; (v) enter into transactions with affiliates; (vi) merge or consolidate with another company; and (vii) transfer and sell assets. These covenants are subject to a number of important exceptions and qualifications. If at any time when our Senior Notes are rated investment grade by both Moody’s Investors Service, Inc. and Standard & Poor’s Ratings Services and no default (as defined in the indentures) has occurred and is continuing, many of such covenants will terminate and we will cease to be subject to such covenants.
Senior unsecured convertible notes. In September 2016, we issued $300.0 million of 2.625% Senior Convertible Notes due September 2023. We have the option to settle conversions of these notes with cash, shares of common stock or a combination of cash and common stock at our election. Our intent is to settle the principal amount of the Senior Convertible Notes in cash upon conversion. Prior to March 15, 2023, the Senior Convertible Notes will be convertible only under the following circumstances: (i) during any calendar quarter (and only during such calendar quarter), if the last reported sale price of our common stock for at least 20 trading days (whether or not consecutive) during the period of 30 consecutive trading days ending on the last trading day of the immediately preceding calendar quarter is greater than or equal to 130% of the conversion price on each applicable trading day; (ii) during the five business day period after any five consecutive trading day period (the “measurement period”) in which the trading price per $1,000 principal amount of the Senior Convertible Notes for each trading day of the measurement period is less than 98% of the product of the last reported sale price of our common stock and the conversion rate on each such trading day; or (iii) upon the occurrence of specified corporate events. On or after March 15, 2023, the Senior Convertible Notes will be convertible at any time until the second scheduled trading day immediately preceding the September 15, 2023 maturity date. The Senior Convertible Notes will be convertible at an initial conversion rate of 76.3650 shares of our common stock per $1,000 principal amount of the notes, which is equivalent to an initial conversion price of approximately $13.10. The conversion rate will be subject to adjustment in some events but will not be adjusted for any accrued and unpaid interest. In addition, following certain corporate events that occur prior to the maturity date or a notice of redemption, we will increase the conversion rate for a holder who elects to convert the Senior Convertible Notes in connection with such corporate event or redemption in certain circumstances. As of June 30, 2017, none of the contingent conditions allowing holders of the Senior Convertible Notes to convert these notes had been met.
Interest on the Senior Notes and the Senior Convertible Notes (collectively, the “Notes”) is payable semi-annually in arrears. The Notes are guaranteed on a senior unsecured basis by our material subsidiaries.
Non-GAAP Financial Measures
Cash Interest, Adjusted EBITDA, Free Cash Flow, Adjusted Net Income (Loss) and Adjusted Diluted Earnings (Loss) Per Share are supplemental non-GAAP financial measures that are used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. These non-GAAP measures should not be considered in isolation or as a substitute for interest expense, net income (loss), operating income (loss), net cash provided by (used in) operating activities, earnings (loss) per share or any other measures prepared under GAAP. Because Cash Interest, Adjusted EBITDA, Free Cash Flow, Adjusted Net Income (Loss) and Adjusted Diluted Earnings (Loss) Per Share exclude some but not all items that affect net income (loss) and may vary among companies, the amounts presented may not be comparable to similar metrics of other companies.
Cash Interest
We define Cash Interest as interest expense plus capitalized interest less amortization and write-offs of deferred financing costs and debt discounts included in interest expense. Cash Interest is not a measure of interest expense as determined by GAAP. Management believes that the presentation of Cash Interest provides useful additional information to investors and analysts for assessing the interest charges incurred on our debt, excluding non-cash amortization, and our ability to maintain compliance with our debt covenants.

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The following table presents a reconciliation of the GAAP financial measure of interest expense to the non-GAAP financial measure of Cash Interest for the periods presented:
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2017
 
2016
 
2017
 
2016
 
(In thousands)
Interest expense
$
36,838

 
$
34,979

 
$
73,159

 
$
73,718

Capitalized interest
2,816

 
4,835

 
5,636

 
9,303

Amortization of deferred financing costs
(1,709
)
 
(2,030
)
 
(3,399
)
 
(5,947
)
Amortization of debt discount
(2,480
)
 
—

 
(4,835
)
 
—

Cash Interest
$
35,465

 
$
37,784

 
$
70,561

 
$
77,074

Adjusted EBITDA and Free Cash Flow
We define Adjusted EBITDA as earnings (loss) before interest expense, income taxes, DD&A, exploration expenses and other similar non-cash or nonrecurring charges. Adjusted EBITDA is not a measure of net income (loss) or cash flows as determined by GAAP. Management believes that the presentation of Adjusted EBITDA provides useful additional information to investors and analysts for assessing our results of operations, financial performance and our ability to generate cash from our business operations without regard to our financing methods or capital structure coupled with our ability to maintain compliance with our debt covenants.
We define Free Cash Flow as Adjusted EBITDA less Cash Interest and capital expenditures, excluding capitalized interest. Free Cash Flow is not a measure of net income (loss) or cash flows as determined by GAAP. Management believes that the presentation of Free Cash Flow provides useful additional information to investors and analysts for assessing our financial performance as compared to our peers and our ability to generate cash from our business operations after interest and capital spending. In addition, Free Cash Flow excludes changes in operating assets and liabilities that relate to the timing of cash receipts and disbursements, which we may not control, and changes in operating assets and liabilities may not relate to the period in which the operating activities occurred.

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The following table presents reconciliations of the GAAP financial measures of net income (loss) and net cash provided by (used in) operating activities to the non-GAAP financial measures of Adjusted EBITDA and Free Cash Flow for the periods presented:
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2017
 
2016
 
2017
 
2016
 
(In thousands)
Net income (loss)
$
16,568

 
$
(89,931
)
 
$
40,393

 
$
(154,386
)
Loss on sale of properties
—

 
1,311

 
—

 
1,311

Gain on extinguishment of debt
—

 
(11,642
)
 
—

 
(18,658
)
Net (gain) loss on derivative instruments
(50,532
)
 
90,846

 
(106,607
)
 
76,471

Derivative settlements(1)
(939
)
 
30,477

 
(8,899
)
 
103,790

Interest expense, net of capitalized interest
36,838

 
34,979

 
73,159

 
73,718

Depreciation, depletion and amortization
125,291

 
122,488

 
251,957

 
244,937

Impairment
3,200

 
23

 
5,882

 
3,585

Exploration expenses
1,667

 
340

 
3,156

 
703

Stock-based compensation expenses
7,115

 
6,249

 
13,823

 
12,979

Income tax (benefit) expense
2,339

 
(52,498
)
 
18,376

 
(80,127
)
Other non-cash adjustments
(213
)
 
(484
)
 
699

 
723

Adjusted EBITDA
141,334

 
132,158

 
291,939


265,046

Cash interest
(35,465
)
 
(37,784
)
 
(70,561
)
 
(77,074
)
Capital expenditures(2)
(172,975
)
 
(131,288
)
 
(282,770
)
 
(219,243
)
Capitalized interest
2,816

 
4,835

 
5,636

 
9,303

Free Cash Flow
$
(64,290
)
 
$
(32,079
)
 
$
(55,756
)

$
(21,968
)
 
 
 
 
 



Net cash provided by operating activities
$
102,062

 
$
137,452

 
$
209,861

 
$
91,401

Derivative settlements(1) 
(939
)
 
30,477

 
(8,899
)
 
103,790

Interest expense, net of capitalized interest
36,838

 
34,979

 
73,159

 
73,718

Exploration expenses
1,667

 
340

 
3,156

 
703

Deferred financing costs amortization and other
(3,931
)
 
(1,486
)
 
(8,871
)
 
(6,552
)
Changes in working capital
5,850

 
(69,120
)
 
22,834

 
1,263

Other non-cash adjustments
(213
)
 
(484
)
 
699

 
723

Adjusted EBITDA
141,334

 
132,158

 
291,939


265,046

Cash interest
(35,465
)
 
(37,784
)
 
(70,561
)
 
(77,074
)
Capital expenditures(2)
(172,975
)
 
(131,288
)
 
(282,770
)
 
(219,243
)
Capitalized interest
2,816

 
4,835

 
5,636

 
9,303

Free Cash Flow
$
(64,290
)
 
$
(32,079
)
 
$
(55,756
)

$
(21,968
)
___________________
(1)
Cash settlements represent the cumulative gains and losses on our derivative instruments for the periods presented and do not include a recovery of costs that were paid to acquire or modify the derivative instruments that were settled.
(2)
Capital expenditures reflected in the table above differ from the amounts shown in the statement of cash flows in our condensed consolidated financial statements because amounts reflected in the table above include changes in accrued liabilities from the previous reporting period for capital expenditures, while the amounts presented in the statement of cash flows are presented on a cash basis.

40
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The following tables present reconciliations of the GAAP financial measure of income (loss) before income taxes to the non-GAAP financial measure of Adjusted EBITDA for our three reportable business segments on a gross basis for the periods presented:
Exploration and Production
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2017
 
2016
 
2017
 
2016
 
(In thousands)
Income (loss) before income taxes
$
(3,900
)
 
$
(158,978
)
 
$
16,836

 
$
(264,744
)
Loss on sale of properties
—

 
1,669

 
—

 
1,669

Gain on extinguishment of debt
—

 
(11,642
)
 
—

 
(18,658
)
Net (gain) loss on derivative instruments
(50,532
)
 
90,846

 
(106,607
)
 
76,471

Derivative settlements(1) 
(939
)
 
30,477

 
(8,899
)
 
103,790

Interest expense, net of capitalized interest
36,838

 
34,979

 
73,159

 
73,718

Depreciation, depletion and amortization
122,785

 
120,039

 
247,193

 
240,881

Impairment
3,200

 
23

 
5,882

 
1,154

Exploration expenses
1,667

 
340

 
3,156

 
703

Stock-based compensation expenses
6,897

 
6,077

 
13,395

 
12,625

Other non-cash adjustments
(213
)
 
(484
)
 
699

 
723

Adjusted EBITDA
$
115,803


$
113,346

 
$
244,814

 
$
228,332

___________________
(1)
Cash settlements represent the cumulative gains and losses on our derivative instruments for the periods presented and do not include a recovery of costs that were paid to acquire or modify the derivative instruments that were settled.
Midstream Services
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2017
 
2016
 
2017
 
2016
 
(In thousands)
Income before income taxes
$
23,106

 
$
18,040

 
$
43,867

 
$
33,198

Gain on sale of properties
—

 
(358
)
 
—

 
(358
)
Depreciation, depletion and amortization
3,753

 
1,732

 
7,211

 
3,415

Impairment
—

 
—

 
—

 
2,431

Stock-based compensation expenses
365

 
224

 
713

 
443

Adjusted EBITDA
$
27,224

 
$
19,638

 
$
51,791

 
$
39,129

Well Services
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2017
 
2016
 
2017
 
2016
 
(In thousands)
Income (loss) before income taxes
$
1,950

 
$
(2,142
)
 
$
(1,637
)
 
$
1,885

Depreciation, depletion and amortization
3,057

 
3,895

 
6,222

 
8,127

Stock-based compensation expenses
338

 
235

 
734

 
899

Adjusted EBITDA
$
5,345

 
$
1,988

 
$
5,319

 
$
10,911


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Adjusted Net Income (Loss) and Adjusted Diluted Earnings (Loss) Per Share
We define Adjusted Net Income (Loss) as net income (loss) after adjusting first for (1) the impact of certain non-cash items, including non-cash changes in the fair value of derivative instruments, impairment and other similar non-cash charges, or non-recurring items and then (2) the non-cash and non-recurring items’ impact on taxes based on our effective tax rate applicable to those adjusting items in the same period. Adjusted Net Income (Loss) is not a measure of net income (loss) as determined by GAAP. We define Adjusted Diluted Earnings (Loss) Per Share as Adjusted Net Income (Loss) divided by diluted weighted average shares outstanding. Management believes that the presentation of Adjusted Net Income (Loss) and Adjusted Diluted Earnings (Loss) Per Share provides useful additional information to investors and analysts for evaluating our operational trends and performance in comparison to our peers. This measure is more comparable to earnings estimates provided by securities analysts, and charges or amounts excluded cannot be reasonably estimated and is excluded from guidance provided by the Company.
The following table presents reconciliations of the GAAP financial measure of net income (loss) to the non-GAAP financial measure of Adjusted Net Income (Loss) and the GAAP financial measure of diluted earnings (loss) per share to the non-GAAP financial measure of Adjusted Diluted Earnings (Loss) Per Share for the periods presented:
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2017
 
2016
 
2017
 
2016
 
(In thousands, except per share data)
Net income (loss)
$
16,568

 
$
(89,931
)
 
$
40,393

 
$
(154,386
)
Loss on sale of properties
—

 
1,311

 
—

 
1,311

Gain on extinguishment of debt
—

 
(11,642
)
 
—

 
(18,658
)
Net (gain) loss on derivative instruments
(50,532
)
 
90,846

 
(106,607
)
 
76,471

Derivative settlements(1)
(939
)
 
30,477

 
(8,899
)
 
103,790

Impairment
3,200

 
23

 
5,882

 
3,585

Amortization of deferred financing costs
1,709

 
2,030

 
3,399

 
5,947

Amortization of debt discount
2,480

 
—

 
4,835

 
—

Other non-cash adjustments
(213
)
 
(484
)
 
699

 
723

Tax impact(2)
16,575

 
(42,075
)
 
37,679

 
(64,731
)
Adjusted Net Loss
$
(11,152
)

$
(19,445
)
 
$
(22,619
)
 
$
(45,948
)
 





 
 
 
 
Diluted earnings (loss) per share
$
0.07

 
$
(0.51
)
 
$
0.17

 
$
(0.91
)
Loss on sale of properties
—

 
0.01

 
—

 
0.01

Gain on extinguishment of debt
—

 
(0.07
)
 
—

 
(0.11
)
Net (gain) loss on derivative instruments
(0.22
)
 
0.51

 
(0.45
)
 
0.45

Derivative settlements(1)
—

 
0.17

 
(0.04
)
 
0.61

Impairment
0.01

 
—

 
0.02

 
0.02

Amortization of deferred financing costs
0.01

 
0.01

 
0.01

 
0.03

Amortization of debt discount
0.01

 
—

 
0.02

 
—

Tax impact(2)
0.07

 
(0.23
)
 
0.17

 
(0.37
)
Non-GAAP Diluted Loss Per Share
$
(0.05
)

$
(0.11
)
 
$
(0.10
)
 
$
(0.27
)
 



 
 
 
 
Diluted weighted average shares outstanding
234,917

 
176,984

 
236,281

 
169,953

 





 
 
 
 
Effective tax rate applicable to adjustment items
37.4
%
 
37.4
%
 
37.4
%
 
37.4
%
___________________
(1)
Cash settlements represent the cumulative gains and losses on our derivative instruments for the periods presented and do not include a recovery of costs that were paid to acquire or modify the derivative instruments that were settled.
(2)
The tax impact is computed utilizing our effective tax rate applicable to the adjustments for certain non-cash and non-recurring items.
Fair Value of Financial Instruments
See Note 4 to our unaudited condensed consolidated financial statements for a discussion of our money market funds and derivative instruments and their related fair value measurements. See also Item 3. “Quantitative and Qualitative Disclosures About Market Risk” below.

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Critical Accounting Policies and Estimates
There have been no material changes in our critical accounting policies and estimates from those disclosed in our 2016 Annual Report. See Note 2 to our unaudited condensed consolidated financial statements for a discussion of additional accounting policies and estimates made by management.
Off-Balance Sheet Arrangements
Currently, we do not have any off-balance sheet arrangements as defined by the SEC. In the ordinary course of business, we enter into various commitment agreements and other contractual obligations, some of which are not recognized in our consolidated financial statements in accordance with GAAP. See Note 13 to our unaudited condensed consolidated financial statements for a description of our commitments and contingencies.
Item 3. — Quantitative and Qualitative Disclosures About Market Risk
The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risk. The term “market risk” refers to the risk of loss arising from adverse changes in prices for oil, natural gas and natural gas liquids, and interest rates.  The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for hedging purposes, rather than for speculative trading. The following market risk disclosures should be read in conjunction with the quantitative and qualitative disclosures about market risk contained in our 2016 Annual Report, as well as with the unaudited condensed consolidated financial statements and notes thereto included in this Quarterly Report on Form 10-Q.
We are exposed to a variety of market risks, including commodity price risk, interest rate risk and counterparty and customer risk. We address these risks through a program of risk management, including the use of derivative instruments.
Commodity price exposure risk. We are exposed to market risk as the prices of oil and natural gas fluctuate as a result of changes in supply and demand and other factors. To partially reduce price risk caused by these market fluctuations, we have entered into derivative instruments in the past and expect to enter into derivative instruments in the future to cover a significant portion of our future production.
We utilize derivative financial instruments to manage risks related to changes in oil and natural gas prices. Our crude oil and natural gas contracts will settle monthly based on the average WTI and the average NYMEX Henry Hub natural gas index price, respectively. As of June 30, 2017, we utilized swaps and two-way and three-way costless collar options to reduce the volatility of oil and natural gas prices on a significant portion of our future expected oil and natural gas production. A swap is a sold call and a purchased put established at the same price (both ceiling and floor), which we will receive for the volumes under contract. A two-way collar is a combination of options: a sold call and a purchased put. The purchased put establishes a minimum price (floor) and the sold call establishes a maximum price (ceiling) we will receive for the volumes under contract. A three-way collar is a combination of options: a sold call, a purchased put and a sold put. The purchased put establishes a minimum price (floor), unless the market price falls below the sold put (sub-floor), at which point the minimum price would be the NYMEX index price plus the difference between the purchased put and the sold put strike price. The sold call establishes a maximum price (ceiling) we will receive for the volumes under contract.
We recognize all derivative instruments at fair value. The credit standing of our counterparties is analyzed and factored into the fair value amounts recognized on the balance sheet. Derivative assets and liabilities arising from our derivative contracts with the same counterparty are also reported on a net basis, as all counterparty contracts provide for net settlement.

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Table of Contents

The following is a summary of our derivative contracts as of June 30, 2017:
Commodity
 
Settlement
Period
 
Derivative
Instrument
 
Volumes
 
Weighted Average Prices
 
Fair Value
Asset (Liability)
 
 
 
 
Swap
 
Sub-Floor
 
Floor
 
Ceiling
 

 
 
 
 
 


 

 
(In thousands)
Crude oil
 
2017
 
Swaps
 
3,843,000

Bbl
 
$
49.83

 
 
 
 
 
 
 
$
13,211

Crude oil
 
2017
 
Two-way collar
 
1,464,000

Bbl
 
 
 
 
 
$
46.25

 
$
54.37

 
3,122

Crude oil
 
2017
 
Three-way collar
 
1,098,000

Bbl
 
 
 
$
31.67

 
$
45.83

 
$
59.94

 
1,816

Crude oil
 
2018
 
Swaps
 
5,508,000

Bbl
 
$
51.95

 
 
 
 
 
 
 
20,746

Crude oil
 
2018
 
Two-way collar
 
582,000

Bbl
 
 
 
 
 
$
48.40

 
$
55.13

 
1,799

Crude oil
 
2018
 
Three-way collar
 
186,000

Bbl
 
 
 
$
31.67

 
$
45.83

 
$
59.94

 
452

Crude oil
 
2019
 
Swaps
 
434,000

Bbl
 
$
52.16

 
 
 
 
 
 
 
1,365

Crude oil
 
2019
 
Two-way collar
 
31,000

Bbl
 
 
 
 
 
$
50.00

 
$
55.70

 
104

Natural gas
 
2017
 
Swaps
 
3,680,000

MMBtu
 
$
3.32

 
 
 
 
 
 
 
827

Natural gas
 
2018
 
Swaps
 
5,475,000

MMBtu
 
$
3.04

 
 
 
 
 
 
 
243

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
$
43,685

A 10% increase in crude oil prices would decrease the fair value of our derivative position by approximately $53.3 million, while a 10% decrease in crude oil prices would increase the fair value by approximately $54.7 million.
Interest rate risk. We had (i) $54.3 million of senior unsecured notes at a fixed cash interest rate of 7.25% per annum, (ii) $395.5 million of senior unsecured notes at a fixed cash interest rate of 6.5% per annum, (iii) $1,303.2 million of senior unsecured notes at a fixed cash interest rate of 6.875% per annum and (iv) $300.0 million of senior unsecured convertible notes as a fixed cash interest rate of 2.625% per annum outstanding at June 30, 2017. At June 30, 2017, we had $418.0 million of borrowings and $10.0 million letters of credit outstanding under our Credit Facility, which were subject to varying rates of interest based on (1) the total outstanding borrowings (including the value of all outstanding letters of credit) in relation to the borrowing base and (2) whether the loan is a LIBOR loan or a domestic bank prime interest rate loan (defined in the Credit Facility as an Alternate Based Rate or “ABR” loan). At June 30, 2017, the outstanding borrowings under our Credit Facility bore interest at LIBOR plus a 1.5% margin. We do not currently, but may in the future, utilize interest rate derivatives to alter interest rate exposure in an attempt to reduce interest rate expense related to debt issued under our Credit Facility. Interest rate derivatives would be used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio.
Counterparty and customer credit risk.  Joint interest receivables arise from billing entities which own partial interest in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we choose to drill. We have limited ability to control participation in our wells. No bad debt expense was recorded during the three and six months ended June 30, 2017. We are also subject to credit risk due to concentration of our oil and natural gas receivables with several significant customers. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results.
While we do not require all of our customers to post collateral and we do not have a formal process in place to evaluate and assess the credit standing of our significant customers for oil and natural gas receivables and the counterparties on our derivative instruments, we do evaluate the credit standing of such counterparties as we deem appropriate under the circumstances. This evaluation may include reviewing a counterparty’s credit rating, latest financial information and, in the case of a customer with which we have receivables, their historical payment record, the financial ability of the customer’s parent company to make payment if the customer cannot and undertaking the due diligence necessary to determine credit terms and credit limits. Several of our significant customers for oil and natural gas receivables have a credit rating below investment grade or do not have rated debt securities. In these circumstances, we have considered the lack of investment grade credit rating in addition to the other factors described above.
In addition, our oil and natural gas derivative arrangements expose us to credit risk in the event of nonperformance by counterparties. However, in order to mitigate the risk of nonperformance, we only enter into derivative contracts with counterparties that are high credit-quality financial institutions, most of which are Lenders under our Credit Facility. This risk is also managed by spreading our derivative exposure across several institutions and limiting the volumes placed under individual contracts. We are likely to enter into future derivative instruments with these or other Lenders under our Credit Facility, which also carry investment grade ratings. Furthermore, the agreements with each of the counterparties on our derivative instruments contain netting provisions. As a result of these netting provisions, our maximum amount of loss due to credit risk is limited to

44
Table of Contents

the net amounts due to and from the counterparties under the derivative contracts. We had a net derivative asset position of $43.7 million at June 30, 2017.
As permitted under our investments policy, we may purchase commercial paper instruments from high credit quality counterparties. These counterparties may include issuers in a variety of industries including the domestic and foreign financial sector. This risk is managed by our investment policy including minimum credit ratings thresholds and maximum counterparty exposure values. Although we do not anticipate any of our commercial paper issuers failing to pay us upon maturity, we take a risk in purchasing the commercial paper instruments available in the marketplace. If an issuer fails to repay us at maturity from commercial paper proceeds, it could take a significant amount of time to recover a portion of or all of the assets originally invested. Our commercial paper balance was $36,000 at June 30, 2017.
Item 4. — Controls and Procedures
Evaluation of disclosure controls and procedures. As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our Chief Executive Officer (“CEO”), our principal executive officer, and our Chief Financial Officer (“CFO”), our principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of June 30, 2017. Our disclosure controls and procedures are designed to provide reasonable assurance that information required to be disclosed by us in the reports filed or submitted by us under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our CEO and CFO as appropriate, to allow timely decisions regarding required disclosure. Based on this evaluation, our CEO and CFO have concluded that our disclosure controls and procedures were effective at June 30, 2017.
Changes in internal control over financial reporting. There were no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that occurred during the three months ended June 30, 2017 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

45
Table of Contents

PART II — OTHER INFORMATION
Item 1. — Legal Proceedings
Mirada litigation. On March 23, 2017, Mirada Energy, LLC, Mirada Wild Basin Holding Company, LLC and Mirada Energy Fund I, LLC (collectively, “Mirada”) filed a lawsuit against Oasis Petroleum Inc., OPNA and OMS, seeking monetary damages in excess of $100 million, declaratory relief, attorneys’ fees and costs (Mirada Energy, LLC, et al. v. Oasis Petroleum North America LLC, et al.; in the 334th Judicial District Court of Harris County, Texas; Case Number 2017-19911). Mirada asserts that it is a working interest owner in certain acreage owned and operated by the Company in Wild Basin. Specifically, Mirada asserts that the Company has breached certain agreements by: (1) failing to allow Mirada to participate in the Company’s midstream operations in Wild Basin; (2) refusing to provide Mirada with information that Mirada contends is required under certain agreements and failing to provide information in a timely fashion; (3) failing to consult with Mirada and failing to obtain Mirada’s consent prior to drilling more than one well at a time in Wild Basin; and (4) by overstating the estimated costs of proposed well operations in Wild Basin. Mirada seeks a declaratory judgment that the Company be removed as operator in Wild Basin at Mirada’s election and that Mirada be allowed to elect a new operator; certain agreements apply to the Company and Mirada and Wild Basin with respect to this dispute; the Company be required to provide all information within its possession regarding proposed or ongoing operations in Wild Basin; and the Company not be permitted to drill, or propose to drill, more than one well at a time in Wild Basin without obtaining Mirada’s consent. Mirada also seeks a declaratory judgment with respect to the Company’s current midstream operations in Wild Basin. Specifically, Mirada seeks a declaratory judgment that Mirada has a right to participate in the Company’s Wild Basin midstream operations, consisting of produced water disposal, crude oil gathering and gas gathering and processing; that, upon Mirada’s election to participate, Mirada is obligated to pay its proportionate costs of the Company’s midstream operations in Wild Basin; and that Mirada would then be entitled to receive a share of revenues from the midstream operations and would not be charged any amount for its use of these facilities for production from the “Contract Area”.
On June 30, 2017, Mirada amended its original petition to add a claim that the Company has breached certain agreements by charging Mirada for midstream services provided by its affiliates and to seek a declaratory judgment that Mirada is entitled to be paid its share of total proceeds from the sale of hydrocarbons received by OPNA or any affiliate of OPNA without deductions for midstream services provided by OPNA or its affiliates.
The Company believes that Mirada’s claims are without merit, that the Company has complied with its obligations under the applicable agreements and that some of Mirada’s claims are grounded in agreements which do not apply to the Company. The Company filed an answer denying Mirada’s claims on April 21, 2017, and intends to vigorously defend against Mirada’s claims. Discovery is ongoing, and trial is currently scheduled for July 2018. However, the Company cannot predict or guarantee the ultimate outcome or resolution of such matter. If such matter were to be determined adversely to the Company’s interests, or if the Company were forced to settle such matter for a significant amount, such resolution or settlement could have a material adverse effect on the Company’s business, results of operations and financial condition. Such an adverse determination could materially impact the Company’s ability to operate its properties in Wild Basin or develop its identified drilling locations in Wild Basin on its current development schedule. A determination that Mirada has a right to participate in the Company’s midstream operations could materially reduce the interests of the Company in their current assets and future midstream opportunities and related revenues in Wild Basin.
Item 1A. — Risk Factors
Our business faces many risks. Any of the risks discussed elsewhere in this Form 10-Q and our other SEC filings could have a material impact on our business, financial position or results of operations. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also impair our business operations.
For a discussion of our potential risks and uncertainties, see the information in Item 1A. “Risk Factors” in our 2016 Annual Report. There have been no material changes in our risk factors from those described in our 2016 Annual Report.

46
Table of Contents

Item 2. — Unregistered Sales of Equity Securities and Use of Proceeds
Unregistered sales of securities. There were no sales of unregistered equity securities during the period covered by this report.
Issuer purchases of equity securities. The following table contains information about our acquisition of equity securities during the three months ended June 30, 2017:
Period
 
Total Number
of Shares
Exchanged(1)
 
Average Price
Paid
per Share
 
Total Number of Shares
Purchased as Part of
Publicly Announced
Plans or Programs
 
Maximum Number (or Approximate
Dollar Value) of Shares that May Be
Purchased Under the
Plans or Programs
April 1 - April 30, 2017
 
1,309

 
$
13.36

 
—

 
—

May 1 - May 31, 2017
 
529

 
11.49

 
—

 
—

June 1 - June 30, 2017
 
797

 
9.88

 
—

 
—

Total
 
2,635

 
$
11.93

 
—

 
—

___________________ 
(1)
Represents shares that employees surrendered back to us to pay tax withholdings upon the vesting of restricted stock awards. These repurchases were not part of a publicly announced program to repurchase shares of our common stock, nor do we have a publicly announced program to repurchase shares of our common stock.
Item 6. — Exhibits
Exhibit
No.
 
Description of Exhibit
 
 
 
 
Eighth Amendment to Second Amended and Restated Credit Agreement dated as of April 10, 2017 among Oasis Petroleum North America LLC, as Borrower, the Guarantors party thereto, Wells Fargo Bank, N.A., as Administrative Agent and the Lenders party thereto (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on April 13, 2017, and incorporated herein by reference).
 
 
 
Sarbanes-Oxley Section 302 certification of Principal Executive Officer.
 
 
 
Sarbanes-Oxley Section 302 certification of Principal Financial Officer.
 
 
 
Sarbanes-Oxley Section 906 certification of Principal Executive Officer.
 
 
 
Sarbanes-Oxley Section 906 certification of Principal Financial Officer.
 
 
101.INS (a)
 
XBRL Instance Document.
 
 
101.SCH (a)
 
XBRL Schema Document.
 
 
101.CAL (a)
 
XBRL Calculation Linkbase Document.
 
 
101.DEF (a)
 
XBRL Definition Linkbase Document.
 
 
101.LAB (a)
 
XBRL Labels Linkbase Document.
 
 
101.PRE (a)
 
XBRL Presentation Linkbase Document.
___________________
(a)
Filed herewith.
(b)
Furnished herewith.



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Table of Contents

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.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
OASIS PETROLEUM INC.
 
 
 
 
 
Date:
August 3, 2017
 
By:
 
/s/ Thomas B. Nusz
 
 
 
 
 
 
 
Thomas B. Nusz
 
 
 
 
 
 
 
Chairman and Chief Executive Officer
(Principal Executive Officer)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
By:
 
/s/ Michael H. Lou
 
 
 
 
 
 
 
Michael H. Lou
 
 
 
 
 
 
 
Executive Vice President and Chief Financial Officer
(Principal Financial Officer and Principal Accounting Officer)


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