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, 2016
or
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                  to                 
Commission file number: 1-34776

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, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. 
Large accelerated filer
ý
Accelerated filer
¨
 
 
 
 
Non-accelerated filer
o  (Do not check if a smaller reporting company)
Smaller reporting company
¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ¨     No   ý
Number of shares of the registrant’s common stock outstanding at August 5, 2016: 180,430,785 shares.
 
 
 
 
 


Table of Contents

OASIS PETROLEUM INC.
FORM 10-Q
FOR THE QUARTER ENDED JUNE 30, 2016
TABLE OF CONTENTS
 
 
Page

Table of Contents

PART I — FINANCIAL INFORMATION
Item 1. — Financial Statements (Unaudited)
Oasis Petroleum Inc.
Condensed Consolidated Balance Sheet
(Unaudited)
 
June 30, 2016
 
December 31, 2015
 
(In thousands, except share data)
ASSETS
 
 
 
Current assets
 
 
 
Cash and cash equivalents
$
6,475

 
$
9,730

Accounts receivable — oil and gas revenues
109,121

 
96,495

Accounts receivable — joint interest and other
81,291

 
100,914

Inventory
9,018

 
11,072

Prepaid expenses
5,838

 
7,328

Derivative instruments
10,330

 
139,697

Other current assets
4,164

 
50

Total current assets
226,237

 
365,286

Property, plant and equipment
 
 
 
Oil and gas properties (successful efforts method)
6,402,648

 
6,284,401

Other property and equipment
536,462

 
443,265

Less: accumulated depreciation, depletion, amortization and impairment
(1,752,376
)
 
(1,509,424
)
Total property, plant and equipment, net
5,186,734

 
5,218,242

Assets held for sale
—

 
26,728

Derivative instruments
64

 
15,776

Other assets
22,504

 
23,343

Total assets
$
5,435,539

 
$
5,649,375

LIABILITIES AND STOCKHOLDERS’ EQUITY
 
 
 
Current liabilities
 
 
 
Accounts payable
$
10,357

 
$
9,983

Revenues and production taxes payable
138,451

 
132,356

Accrued liabilities
128,284

 
167,669

Accrued interest payable
47,671

 
49,413

Derivative instruments
20,891

 
—

Advances from joint interest partners
5,416

 
4,647

Other current liabilities
15,001

 
6,500

Total current liabilities
366,071

 
370,568

Long-term debt
2,127,361

 
2,302,584

Deferred income taxes
528,028

 
608,155

Asset retirement obligations
36,390

 
35,338

Liabilities held for sale
—

 
10,228

Derivative instruments
14,291

 
—

Other liabilities
3,043

 
3,160

Total liabilities
3,075,184

 
3,330,033

Commitments and contingencies (Note 15)

 

Stockholders’ equity
 
 
 
Common stock, $0.01 par value: 450,000,000 and 300,000,000 shares authorized at June 30, 2016 and December 31, 2015, respectively; 181,200,581 shares issued and 180,399,060 shares outstanding at June 30, 2016 and 139,583,990 shares issued and 139,076,064 shares outstanding at December 31, 2015
1,777

 
1,376

Treasury stock, at cost: 801,521 and 507,926 shares at June 30, 2016 and December 31, 2015, respectively
(15,140
)
 
(13,620
)
Additional paid-in capital
1,693,583

 
1,497,065

Retained earnings
680,135

 
834,521

Total stockholders’ equity
2,360,355

 
2,319,342

Total liabilities and stockholders’ equity
$
5,435,539

 
$
5,649,375

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

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Oasis Petroleum Inc.
Condensed Consolidated Statement of Operations
(Unaudited)
 
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2016
 
2015
 
2016
 
2015
 
(In thousands, except per share data)
Revenues
 
 
 
 
 
 
 
Oil and gas revenues
$
159,337

 
$
214,110

 
$
276,652

 
$
387,969

Well services and midstream revenues
19,743

 
15,936

 
32,711

 
22,464

Total revenues
179,080

 
230,046

 
309,363

 
410,433

Operating expenses
 
 
 
 
 
 
 
Lease operating expenses
31,523

 
37,761

 
62,587

 
76,886

Well services and midstream operating expenses
8,875

 
7,395

 
13,264

 
9,347

Marketing, transportation and gathering expenses
6,491

 
7,570

 
15,043

 
14,848

Production taxes
14,367

 
20,618

 
25,120

 
37,239

Depreciation, depletion and amortization
122,488

 
119,218

 
244,937

 
237,696

Exploration expenses
340

 
1,082

 
703

 
1,925

Rig termination
—

 
2,815

 
—

 
3,895

Impairment
23

 
19,516

 
3,585

 
24,837

General and administrative expenses
21,876

 
21,508

 
46,242

 
44,832

Total operating expenses
205,983

 
237,483

 
411,481

 
451,505

Loss on sale of properties
(1,311
)
 
—

 
(1,311
)
 
—

Operating loss
(28,214
)
 
(7,437
)
 
(103,429
)
 
(41,072
)
Other income (expense)
 
 
 
 
 
 
 
Net gain (loss) on derivative instruments
(90,846
)
 
(39,424
)
 
(76,471
)
 
7,648

Interest expense, net of capitalized interest
(34,979
)
 
(37,405
)
 
(73,718
)
 
(76,189
)
Gain on extinguishment of debt
11,642

 
—

 
18,658

 
—

Other income (expense)
(32
)
 
191

 
447

 
121

Total other income (expense)
(114,215
)
 
(76,638
)
 
(131,084
)
 
(68,420
)
Loss before income taxes
(142,429
)
 
(84,075
)
 
(234,513
)
 
(109,492
)
Income tax benefit
52,498

 
30,845

 
80,127

 
38,221

Net loss
$
(89,931
)
 
$
(53,230
)
 
$
(154,386
)
 
$
(71,271
)
Loss per share:
 
 
 
 
 
 
 
Basic (Note 13)
$
(0.51
)
 
$
(0.39
)
 
$
(0.91
)
 
$
(0.58
)
Diluted (Note 13)
(0.51
)
 
(0.39
)
 
(0.91
)
 
(0.58
)
Weighted average shares outstanding:
 
 
 
 
 
 
 
Basic (Note 13)
176,984

 
136,859

 
169,953

 
123,157

Diluted (Note 13)
176,984

 
136,859

 
169,953

 
123,157

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, 2015
139,076

 
$
1,376

 
508

 
$
(13,620
)
 
$
1,497,065

 
$
834,521

 
$
2,319,342

Issuance of common stock
39,100

 
391

 
—

 
—

 
182,562

 
—

 
182,953

Stock-based compensation
2,517

 
—

 
—

 
—

 
13,966

 
—

 
13,966

Vesting of restricted shares
—

 
10

 
—

 
—

 
(10
)
 
—

 
—

Treasury stock – tax withholdings
(294
)
 
—

 
294

 
(1,520
)
 
—

 
—

 
(1,520
)
Net loss
—

 
—

 
—

 
—

 
—

 
(154,386
)
 
(154,386
)
Balance at June 30, 2016
180,399

 
$
1,777

 
802

 
$
(15,140
)
 
$
1,693,583

 
$
680,135

 
$
2,360,355

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


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Oasis Petroleum Inc.
Condensed Consolidated Statement of Cash Flows
(Unaudited)
 
Six Months Ended June 30,
 
2016
 
2015
 
(In thousands)
Cash flows from operating activities:
 
 
 
Net loss
$
(154,386
)
 
$
(71,271
)
Adjustments to reconcile net loss to net cash provided by operating activities:
 
 
 
Depreciation, depletion and amortization
244,937

 
237,696

Gain on extinguishment of debt
(18,658
)
 
—

Loss on sale of properties
1,311

 
—

Impairment
3,585

 
24,837

Deferred income taxes
(80,127
)
 
(38,221
)
Derivative instruments
76,471

 
(7,648
)
Stock-based compensation expenses
12,979

 
13,663

Deferred financing costs amortization and other
6,552

 
5,059

Working capital and other changes:
 
 
 
Change in accounts receivable
4,297

 
75,799

Change in inventory
2,054

 
3,685

Change in prepaid expenses
1,423

 
3,394

Change in other current assets
(114
)
 
5,538

Change in other assets
100

 
—

Change in accounts payable, interest payable and accrued liabilities
(18,034
)
 
(22,624
)
Change in other current liabilities
9,001

 
—

Change in other liabilities
10

 
(21
)
Net cash provided by operating activities
91,401

 
229,886

Cash flows from investing activities:
 
 
 
Capital expenditures
(231,341
)
 
(587,430
)
Proceeds from sale of properties
11,679

 
—

Costs related to sale of properties
(310
)
 
—

Derivative settlements
103,790

 
213,336

Advances from joint interest partners
769

 
(406
)
Net cash used in investing activities
(115,413
)
 
(374,500
)
Cash flows from financing activities:
 
 
 
Proceeds from revolving credit facility
359,000

 
320,000

Principal payments on revolving credit facility
(462,000
)
 
(665,000
)
Repurchase of senior unsecured notes
(56,925
)
 
—

Deferred financing costs
(751
)
 
(3,591
)
Proceeds from sale of common stock
182,953

 
463,010

Purchases of treasury stock
(1,520
)
 
(1,932
)
Net cash provided by financing activities
20,757

 
112,487

Decrease in cash and cash equivalents
(3,255
)
 
(32,127
)
Cash and cash equivalents:
 
 
 
Beginning of period
9,730

 
45,811

End of period
$
6,475

 
$
13,684

Supplemental non-cash transactions:
 
 
 
Change in accrued capital expenditures
$
(17,015
)
 
$
(156,368
)
Change in asset retirement obligations
(8,785
)
 
2,649

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 well services business through Oasis Well Services LLC (“OWS”) and a midstream services business through Oasis Midstream Services LLC (“OMS”), 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, 2015 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, 2015 (“2015 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. Oil and natural gas prices have declined significantly since mid-2014. As a result of sustained lower commodity prices, the Company decreased its 2016 capital expenditures as compared to 2015 and continues to concentrate its drilling activities in certain areas that are the most economic in the Williston Basin. 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 2015 Annual Report.
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

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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.
Going concern. In August 2014, the FASB issued Accounting Standards Update No. 2014-15, Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern (“ASU 2014-15”). ASU 2014-15 codifies in GAAP management’s responsibility to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern and to provide related footnote disclosures. ASU 2014-15 is effective for the annual reporting period ending after December 15, 2016 and for annual periods and interim periods thereafter. The adoption of this guidance will not impact the Company’s financial position, cash flows or results of operations but could result in additional disclosures.
Inventory. In July 2015, the FASB issued Accounting Standards Update No. 2015-11, Simplifying the Measurement of Inventory (“ASU 2015-11”). ASU 2015-11 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 (FIFO) or average cost methods. ASU 2015-11 is effective for fiscal years beginning after December 15, 2016, 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.
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.
Embedded derivatives. In March 2016, the FASB issued Accounting Standards Update No. 2016-06, Contingent Put and Call Options in Debt Instruments (“ASU 2016-06”), which clarifies what steps are required when assessing whether the economic characteristics and risks of call (put) options are clearly and closely related to the economic characteristics and risks of their debt hosts, which is one of the criteria for bifurcating an embedded derivative. ASU 2016-06 is effective for fiscal years beginning after December 15, 2016, including interim periods within those years. The Company does not expect the adoption of this guidance to have a material impact on its financial position, cash flows or results of operations.
Stock-based compensation. In March 2016, the FASB issued 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. ASU 2016-09 is effective for fiscal years beginning after December 15, 2016, 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.
3. Inventory
Crude oil inventory includes oil in tank and linefill. 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. Inventory is stated at the lower of cost or market value with cost determined on an average cost method. Inventory consists of the following:
 
June 30, 2016
 
December 31, 2015
 
(In thousands)
Crude oil inventory
$
5,430

 
$
6,152

Equipment and materials
3,588

 
4,920

Total inventory
$
9,018

 
$
11,072


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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 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 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, 2016
 
Level 1
 
Level 2
 
Level 3
 
Total
 
(In thousands)
Assets:
 
 
 
 
 
 
 
Money market funds
$
54

 
$
—

 
$
—

 
$
54

Commodity derivative instruments (see Note 5)
—

 
10,394

 
—

 
10,394

Total assets
$
54

 
$
10,394

 
$
—

 
$
10,448

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

 
$
35,182

 
$
—

 
$
35,182

Total liabilities
$
—

 
$
35,182

 
$
—

 
$
35,182

 
 
 
 
 
 
 
 
 
Fair value at December 31, 2015
 
Level 1
 
Level 2
 
Level 3
 
Total
 
(In thousands)
Assets:
 
 
 
 
 
 
 
Money market funds
$
742

 
$
—

 
$
—

 
$
742

Commodity derivative instruments (see Note 5)
—

 
155,473

 
—

 
155,473

Total assets
$
742

 
$
155,473

 
$
—

 
$
156,215


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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 Sheet at June 30, 2016 and December 31, 2015. 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 collars and swaps. 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. However, the Company does not have access to the specific proprietary valuation models or inputs used by its counterparties or third-party preparer. 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 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 liability by $2.4 million at June 30, 2016 and an adjustment to reduce the fair value of its net derivative asset by $0.3 million at December 31, 2015.
There were no transfers between fair value levels during the six months ended June 30, 2016 and 2015.

Fair Value of Other Financial Instruments
The Company’s financial instruments, including certain cash and cash equivalents, accounts receivable and accounts payable, are carried at cost, which approximates fair value due to the short-term maturity of these instruments. At June 30, 2016, the Company’s cash equivalents were all Level 1 assets.
The carrying amount of the Company’s long-term debt reported in the Condensed Consolidated Balance Sheet at June 30, 2016 was $2,127.4 million, which included $2,123.4 million of senior unsecured notes, $35.0 million of borrowings under the revolving credit facility and a $31.0 million reduction for deferred financing costs on the senior unsecured notes (see Note 8 – Long-Term Debt). The fair value of the Company’s senior unsecured notes, which are publicly traded and therefore categorized as Level 1 liabilities, was $1,965.2 million at June 30, 2016.
Non-Financial Assets and Liabilities
Asset retirement obligations. The carrying amount of ARO in the Company’s Condensed Consolidated Balance Sheet at June 30, 2016 was $37.1 million (see Note 9 – Asset Retirement Obligations). The Company determines its ARO by calculating the present value of estimated cash flows related to the liability. Estimating the future ARO requires management to make estimates and judgments regarding the timing and existence of a liability, as well as what constitutes adequate restoration when considering current regulatory requirements. Inherent in the fair value calculation are numerous assumptions and judgments, including the ultimate costs, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. These assumptions represent Level 3 inputs. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the related asset.
Impairment. The Company reviews its proved oil and natural gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. The Company estimates the expected undiscounted future cash flows of its proved oil and natural gas properties and then compares such undiscounted future cash flows to the carrying amount of the proved oil and natural gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will adjust the carrying amount of the proved oil and natural gas properties to the fair value. The factors used to determine fair value are subject to management’s judgment and expertise and include, but are not limited to, recent sales prices of comparable properties, the present value of future cash flows, net of estimated operating and development costs, using estimates of proved reserves, future commodity pricing, future production estimates, anticipated capital expenditures and various discount rates commensurate with the risk and current market conditions associated with realizing the expected cash flows projected. These assumptions represent Level 3 inputs.

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On April 1, 2016, the Company sold certain proved oil and natural gas properties and other midstream properties (see Note 7 – Divestiture). For the six months ended June 30, 2016, the Company recorded an impairment charge of $3.6 million, of which $2.4 million was included in its midstream services segment and $1.2 million was included in its exploration and production segment, to adjust the current carrying value of these assets, net of the associated ARO liabilities, to their estimated fair value. For the year ended December 31, 2015, the Company recorded an impairment charge of $9.4 million to adjust its net assets held for sale to their estimated fair value in its exploration and production segment. The fair value was determined based on the expected sales price, less costs to sell. No other impairment charges on proved oil and natural gas properties were recorded for the six months ended June 30, 2016. No impairment charges on proved oil and natural gas properties were recorded for the three months ended June 30, 2016 and the three and six months ended June 30, 2015.
In addition, as a result of expiring leases, the Company recorded non-cash impairment charges on its unproved oil and natural gas properties of $23,000 and $25,000 for the three and six months ended June 30, 2016, respectively, and $0.4 million and $4.5 million for the three and six months ended June 30, 2015, respectively. As a result of periodic assessments of unproved properties, the Company recorded non-cash impairment charges on its unproved oil and natural gas properties of $19.1 million and $20.3 million for the three and six months ended June 30, 2015, respectively, 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 and six months ended June 30, 2016, the Company did not record similar impairment charges.
5. Derivative Instruments
The Company utilizes derivative financial instruments to manage risks related to changes in oil prices. At June 30, 2016, the Company utilized two-way and three-way costless collar options and swaps to reduce the volatility of oil prices on a significant portion of its future expected oil production. 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 West Texas Intermediate crude oil index price (“WTI”) 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. A swap is a sold call and a purchased put established at the same price (both ceiling and floor).
All derivative instruments are recorded on the Company’s Condensed Consolidated Balance Sheet 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 Statement 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 Statement of Cash Flows.
At June 30, 2016, the Company had the following outstanding commodity derivative instruments, all of which settle monthly based on the average WTI:
Settlement
Period
 
Derivative
Instrument
 
Total Notional
Amount of Oil
 
Weighted Average Prices
 
Fair Value
Asset (Liability)
 
 
 
Swap
 
Sub-Floor
 
Floor
 
Ceiling
 
 
 
 
 
(Barrels)
 
($/Barrel)
 
(In thousands)
2016
 
Swaps
 
5,886,000

 
$
49.64

 
 
 
 
 
 
 
$
1,157

2017
 
Swaps
 
4,694,000

 
$
47.79

 
 
 
 
 
 
 
(18,429
)
2017
 
Two-way collars
 
668,000

 
 
 
 
 
$
40.00

 
$
47.58

 
(4,427
)
2017
 
Three-way collars
 
1,336,000

 

 
$
30.00

 
$
45.00

 
$
59.39

 
(923
)
2018
 
Swaps
 
310,000

 
$
47.68

 
 
 

 

 
(1,519
)
2018
 
Two-way collars
 
62,000

 
 
 
 
 
$
40.00

 
$
47.58

 
(453
)
2018
 
Three-way collars
 
124,000

 
 
 
$
30.00

 
$
45.00

 
$
59.39

 
(194
)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
$
(24,788
)

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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 Sheet: 
 
 
 
 
Fair Value Asset (Liability)
Commodity
 
Balance Sheet Location
 
June 30, 2016
 
December 31, 2015
 
 
 
 
(In thousands)
Crude oil
 
Derivative instruments — current assets
 
$
10,330

 
$
139,697

Crude oil
 
Derivative instruments — non-current assets
 
64

 
15,776

Crude oil
 
Derivative instruments — current liabilities
 
(20,891
)
 
—

Crude oil
 
Derivative instruments — non-current liabilities
 
(14,291
)
 
—

Total derivative instruments
 
$
(24,788
)
 
$
155,473

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 Statement of Operations for the periods presented:
 
 
Three Months Ended June 30,
 
Six Months Ended June 30,
Statement of Operations Location
 
2016
 
2015
 
2016
 
2015
 
 
(In thousands)
Net gain (loss) on derivative instruments
 
$
(90,846
)
 
$
(39,424
)
 
$
(76,471
)
 
$
7,648

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 Sheet.
The following tables summarize gross and net information about the Company’s commodity derivative instruments:
Offsetting of Derivative Assets
 
Gross Amounts of Recognized Assets
 
Gross Amounts Offset
in the Balance Sheet
 
Net Amounts of Assets Presented
in the Balance Sheet
 
 
(In thousands)
At June 30, 2016
 
$
24,900

 
$
(14,506
)
 
$
10,394

At December 31, 2015
 
155,473

 
—

 
155,473

Offsetting of Derivative Liabilities
 
Gross Amounts of Recognized Liabilities
 
Gross Amounts Offset
in the Balance Sheet
 
Net Amounts of Liabilities Presented
in the Balance Sheet
 
 
(In thousands)
At June 30, 2016
 
$
49,688

 
$
(14,506
)
 
$
35,182

At December 31, 2015
 
—

 
—

 
—



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6. Property, Plant and Equipment
The following table sets forth the Company’s property, plant and equipment:
 
June 30, 2016
 
December 31, 2015
 
(In thousands)
Proved oil and gas properties(1)
$
5,774,121

 
$
5,655,759

Less: accumulated depreciation, depletion, amortization and impairment
(1,657,641
)
 
(1,428,427
)
Proved oil and gas properties, net
4,116,480

 
4,227,332

Unproved oil and gas properties
628,527

 
628,642

Other property and equipment
536,462

 
443,265

Less: accumulated depreciation
(94,735
)
 
(80,997
)
Other property and equipment, net
441,727

 
362,268

Total property, plant and equipment, net
$
5,186,734

 
$
5,218,242

 __________________
(1)
Included in the Company’s proved oil and gas properties are estimates of future asset retirement costs of $31.3 million and $30.7 million at June 30, 2016 and December 31, 2015, respectively.
7. Divestiture
On April 1, 2016, the Company completed the sale of certain legacy wells that have been producing from conventional reservoirs such as the Madison, Red River and other formations in the Williston Basin other than the Bakken or Three Forks formations for cash proceeds of approximately $12.2 million, which includes, and is subject to further, customary post close adjustments, and a $4.0 million 10% secured promissory note due within one year. These sold assets primarily consisted of oil and gas properties in the Company’s exploration and production segment and included certain other property and equipment in the Company’s midstream segment.
For the six months ended June 30, 2016 and the year ended December 31, 2015, the Company recorded impairment charges of $3.6 million and $9.4 million, respectively, which were included in impairment on the Company’s Condensed Consolidated Statement of Operations, to adjust the carrying value of these assets to their estimated fair value, determined based on the expected sales price, less costs to sell. There were no similar charges recorded during the three months ended June 30, 2016 and three and six months ended June 30, 2015. For the three and six months ended June 30, 2016, customary post close adjustments were included in the loss on sale of properties on the Company’s Condensed Consolidated Statement of Operations.

8. Long-Term Debt
The Company’s long-term debt consists of the following:
 
June 30, 2016
 
December 31, 2015
 
(In thousands)
Senior secured revolving line of credit
$
35,000

 
$
138,000

Senior unsecured notes
 
 
 
7.25% senior unsecured notes due February 1, 2019
399,000

 
400,000

6.5% senior unsecured notes due November 1, 2021
397,697

 
400,000

6.875% senior unsecured notes due March 15, 2022
940,500

 
1,000,000

6.875% senior unsecured notes due January 15, 2023
386,200

 
400,000

Less: deferred financing costs related to senior unsecured notes
(31,036
)
 
(35,416
)
Total long-term debt
$
2,127,361

 
$
2,302,584

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, 2016, which has a maturity date of April 13, 2020. 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 February 23, 2016, the lenders under the Credit Facility completed their regular semi-annual redetermination of the borrowing base scheduled for April 1, 2016, resulting in a decrease in the borrowing base and aggregate elected commitment from $1,525.0 million to $1,150.0 million.

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As of June 30, 2016, the Company had $35.0 million of LIBOR loans and $14.2 million of outstanding letters of credit issued under the Credit Facility, resulting in an unused borrowing base committed capacity of $1,100.8 million. The weighted average interest rate on borrowings outstanding under the Credit Facility was 2.0% and 1.9% as of June 30, 2016 and December 31, 2015, respectively. On a quarterly basis, the Company also pays a 0.375% (as of June 30, 2016) 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, 2016.
Senior unsecured notes. At June 30, 2016, the Company had $2,123.4 million principal amount of senior unsecured notes outstanding with maturities ranging from February 2019 to January 2023 and coupons ranging from 6.5% to 7.25% (the “Notes”). Interest on 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.
Prior to certain dates, the Company has certain options to redeem up to 35% of the Notes at a certain redemption price based on a percentage of the principal amount, plus accrued and unpaid interest to the redemption date, with the proceeds of certain equity offerings so long as the redemption occurs within 180 days of completing such equity offering and at least 65% of the aggregate principal amount of the Notes remains outstanding after such redemption. Prior to certain dates, the Company has the option to redeem some or all of the 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 Company estimates that the fair value of these redemption options is immaterial at June 30, 2016 and December 31, 2015.
During the six months ended June 30, 2016, the Company repurchased an aggregate principal amount of $76.6 million of its outstanding Notes, consisting of $1.0 million principal amount of its 7.25% senior unsecured notes due February 2019, $2.3 million principal amount of its 6.5% senior unsecured notes due November 2021, $59.5 million principal amount of its 6.875% senior unsecured notes due March 2022 and $13.8 million principal amount of its 6.875% senior unsecured notes due January 2023, for an aggregate cost of $56.9 million, including accrued interest and fees. For the three and six months ended June 30, 2016, the Company recognized pre-tax gains of $11.6 million and $18.7 million, respectively, related to these repurchases, which were net of unamortized deferred financing costs write-offs of $0.5 million and $1.0 million, respectively, and are reflected in gain on extinguishment of debt in the Company’s Condensed Consolidated Statement of Operations.
Deferred financing costs. At June 30, 2016, the Company had $36.7 million of deferred financing costs related to the Notes and the Credit Facility. Deferred financing costs of $31.0 million related to the Notes are included in long-term debt on the Company’s Condensed Consolidated Balance Sheet at June 30, 2016, and are being amortized over the respective terms of the Notes. Deferred financing costs of $5.7 million related to the Credit Facility are included in other assets on the Company’s Condensed Consolidated Balance Sheet at June 30, 2016, and are being amortized over the term of the Credit Facility. Amortization of deferred financing costs recorded was $2.0 million and $4.1 million for the three and six months ended June 30, 2016, respectively, and $1.9 million and $3.5 million for the three and six months ended June 30, 2015, respectively. These costs are included in interest expense on the Company’s Condensed Consolidated Statement of Operations. For the six months ended June 30, 2016 and 2015, the Company’s interest expense also included $1.8 million and $0.5 million charges for unamortized deferred financing costs related to the Credit Facility, which were written off in proportion to the decreases in the borrowing base. No deferred financing costs related to the Credit Facility were written off during the three months ended June 30, 2016. Aforementioned, the gain on extinguishment of debt in the Company’s Condensed Consolidated Statement of Operations included unamortized deferred financing costs write-offs of $0.5 million and $1.0 million related to the repurchased Notes for the three and six months ended June 30, 2016, respectively. No deferred financing costs related to the Notes were written off during the three and six months ended June 30, 2015.

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9. Asset Retirement Obligations
The following table reflects the changes in the Company’s ARO during the six months ended June 30, 2016:
 
(In thousands)
Balance at December 31, 2015
$
35,812

Liabilities incurred during period
248

Liabilities settled during period(1)
(443
)
Accretion expense during period(2)
940

Revisions to estimates
571

Balance at June 30, 2016
$
37,128

___________________
(1)
Liabilities settled during the six months ended June 30, 2016 included ARO related to the sold properties (see Note 7 – Divestiture).
(2)
Included in depreciation, depletion and amortization on the Company’s Condensed Consolidated Statement of Operations.
At June 30, 2016, the current portion of the total ARO balance was approximately $0.7 million and was included in accrued liabilities on the Company’s Condensed Consolidated Balance Sheet.
10. Income Taxes
The Company’s effective tax rate for the three and six months ended June 30, 2016 was 36.9% and 34.2%, respectively. The Company’s effective tax rate for the three and six months ended June 30, 2015 was 36.7% and 34.9%, respectively. The effective tax rates for both the six months ended June 30, 2016 and 2015 were 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 each period. The permanent differences were primarily between amounts expensed for book purposes versus the amounts deductible for income tax purposes related to stock-based compensation vesting during the six months ended June 30, 2016 and 2015 at stock prices lower than the grant date values.
While the Company is in an overall deferred tax liability position, the Company had deferred tax assets for its federal and state tax net operating losses and other tax carryforwards recorded in deferred income taxes at June 30, 2016. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized. During the six months ended June 30, 2016, the Company recorded a valuation allowance of $0.9 million and $0.6 million for Montana net operating losses and for federal charitable contribution carryovers, respectively, based on management’s assessment that it is more likely than not that these net deferred tax assets will not be realized prior to their expiration due to their short carryover periods, current economic conditions and expectations for the future. Management determined that a valuation allowance was not required for its U.S. federal tax net operating loss carryforwards as they are expected to be fully utilized before their expiration. However, the amount of deferred tax assets considered realizable could be reduced in the future if subjective positive evidence, such as projections of future growth, become limited by objective negative evidence, such as projected cumulative losses incurred over a three-year period. Management’s estimates of future taxable income are significantly affected by changes in commodity prices, the timing and amount of future production and future operating and capital costs.
At June 30, 2016, the Company did not have any uncertain tax positions requiring adjustments to its tax liability.
11. Common Stock
On February 2, 2016, the Company completed a public offering of 39,100,000 shares of its common stock (including 5,100,000 shares issued pursuant to the underwriters’ option to purchase additional common stock) at an offering price of $4.685 per share. Net proceeds from the offering were $183.0 million, after deducting underwriting discounts and commissions and offering expenses, of which $0.4 million is included in common stock and $182.6 million is included in additional paid-in capital on the Company’s Condensed Consolidated Balance Sheet at June 30, 2016. The Company used the net proceeds for general corporate purposes. The offering was made pursuant to an effective shelf registration statement on Form S-3 filed with the SEC on July 15, 2014.
12. 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

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stock grants 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. For the six months ended June 30, 2016, the Company assumed annual forfeiture rates by employee group ranging from 0% to 20.0% based on the Company’s forfeiture history for this type of award.
During the six months ended June 30, 2016, employees and non-employee directors of the Company were granted restricted stock awards equal to 2,573,950 shares of common stock with a $4.34 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, 2016 was $4.9 million and $10.7 million, respectively, and $5.1 million and $11.8 million for the three and six months ended June 30, 2015, respectively. Stock-based compensation expense is included in general and administrative expenses on the Company’s Condensed Consolidated Statement 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. For the six months ended June 30, 2016, the Company assumed annual forfeiture rates by employee group ranging from 3.3% to 4.6% based on the Company’s forfeiture history for the officer employee groups receiving PSUs.
During the six months ended June 30, 2016, officers of the Company were granted 910,000 PSUs with a $3.00 weighted average grant date per share value. Stock-based compensation expense recorded for PSUs for the three and six months ended June 30, 2016 was $1.3 million and $2.2 million, respectively, and $1.0 million and $1.9 million for the three and six months ended June 30, 2015, respectively. Stock-based compensation expense is included in general and administrative expenses on the Company’s Condensed Consolidated Statement 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. The grant date fair value for each grant of PSUs is recognized on a straight-line basis over a four-year total performance period. 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, which results in an expected percentage of PSUs earned. 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 rate is the U.S. Treasury bond rate on the date of grant that corresponds to the total 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 is the standard deviation of the average percentage change in stock price 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, 2016:
Forecast period (years)
4.00

Risk-free interest rate
1.25
%
Oasis stock price volatility
59.38
%
For the PSUs granted during the six months ended June 30, 2016, the Monte Carlo simulation model resulted in approximately 69% of PSUs expected to be earned.

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13. 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 impact of potentially dilutive non-vested restricted shares and PSUs outstanding during the periods presented, unless their effect is anti-dilutive. There are no adjustments made to the earnings (loss) attributable 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, 2016 and 2015: 
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2016
 
2015
 
2016
 
2015
 
(In thousands)
Basic weighted average common shares outstanding
176,984

 
136,859

 
169,953

 
123,157

Dilution effect of stock awards at end of period(1)
—

 
—

 
—

 
—

Diluted weighted average common shares outstanding
176,984

 
136,859

 
169,953

 
123,157

Anti-dilutive stock-based compensation awards
4,920

 
2,993

 
4,794

 
3,012

___________________
(1)
No unvested stock awards were included in computing loss per share for the three and six months ended June 30, 2016 and 2015 because the effect was anti-dilutive.

14. 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 well services business segment (OWS) performs 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 Company’s midstream services business segment (OMS) performs salt water gathering and disposal 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 and fresh water sales. The revenues and expenses related to work performed by OWS and OMS 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 Statement 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, which is defined as segment operating revenues less operating expenses, including depreciation, depletion and amortization. The following table summarizes financial information for the Company’s three business segments for the periods presented: 
 
Exploration and
Production
 
Well Services
 
Midstream Services
 
Eliminations
 
Consolidated
 
(In thousands)
Three months ended June 30, 2016:
 
Revenues from non-affiliates
$
159,337

 
$
12,834

 
$
6,909

 
$
—

 
$
179,080

Inter-segment revenues
—

 
8,301

 
22,026

 
(30,327
)
 
—

Total revenues
159,337

 
21,135

 
28,935

 
(30,327
)
 
179,080

Operating income (loss)
(44,748
)
 
(2,173
)
 
18,056

 
651

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

 
(16
)
 
—

 
(114,215
)
Income (loss) before income taxes
$
(158,978
)
 
$
(2,142
)
 
$
18,040

 
$
651

 
$
(142,429
)
 
 
Three months ended June 30, 2015:
 
 
 
 
 
 
 
 
 
Revenues from non-affiliates
$
214,110

 
$
9,219

 
$
6,717

 
$
—

 
$
230,046

Inter-segment revenues
—

 
49,469

 
21,944

 
(71,413
)
 
—

Total revenues
214,110

 
58,688

 
28,661

 
(71,413
)
 
230,046

Operating income (loss)
(22,529
)
 
9,008

 
15,947

 
(9,863
)
 
(7,437
)
Other income (expense)
(76,635
)
 
22

 
(25
)
 
—

 
(76,638
)
Income (loss) before income taxes
$
(99,164
)
 
$
9,030

 
$
15,922

 
$
(9,863
)
 
$
(84,075
)
 
 
 
 
 
 
 
 
 
 
Six months ended June 30, 2016:
 
 
 
 
 
 
 
 
 
Revenues from non-affiliates
$
276,652

 
$
18,818

 
$
13,893

 
$
—

 
$
309,363

Inter-segment revenues
—

 
33,205

 
44,860

 
(78,065
)
 
—

Total revenues
276,652

 
52,023

 
58,753

 
(78,065
)
 
309,363

Operating income (loss)
(133,625
)
 
1,848

 
33,200

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

 
(2
)
 
—

 
(131,084
)
Income (loss) before income taxes
$
(264,744
)
 
$
1,885

 
$
33,198

 
$
(4,852
)
 
$
(234,513
)
 
 
Six months ended June 30, 2015:
 
 
 
 
 
 
 
 
 
Revenues from non-affiliates
$
387,969

 
$
11,927

 
$
10,537

 
$
—

 
$
410,433

Inter-segment revenues
—

 
97,666

 
35,766

 
(133,432
)
 
—

Total revenues
387,969

 
109,593

 
46,303

 
(133,432
)
 
410,433

Operating income (loss)
(64,776
)
 
18,618

 
25,255

 
(20,169
)
 
(41,072
)
Other income (expense)
(68,396
)
 
20

 
(44
)
 
—

 
(68,420
)
Income (loss) before income taxes
$
(133,172
)
 
$
18,638

 
$
25,211

 
$
(20,169
)
 
$
(109,492
)
 
 
At June 30, 2016:
 
Property, plant and equipment, net
$
4,951,972

 
$
53,926

 
$
351,116

 
$
(170,280
)
 
$
5,186,734

Total assets(1)
5,191,725

 
57,482

 
356,612

 
(170,280
)
 
5,435,539

At December 31, 2015:
 
 
 
 
 
 
 
 
 
Property, plant and equipment, net
$
5,057,311

 
$
61,402

 
$
264,956

 
$
(165,427
)
 
$
5,218,242

Total assets(1)(2)
5,478,439

 
66,952

 
269,411

 
(165,427
)
 
5,649,375

___________________
(1)
Intercompany receivables (payables) for all segments were reclassified to capital contributions from (distributions to) parent and not included in total assets.
(2)
At December 31, 2015, total assets included assets held for sale of $26.7 million in the exploration and production segment related to the assets sold as of April 1, 2016 (see Note 7 – Divestiture).

16
Table of Contents

15. Commitments and Contingencies
Included below is a discussion of the Company’s various future commitments as of June 30, 2016. The commitments under these arrangements are not recorded in the accompanying Condensed Consolidated Balance Sheet. The amounts disclosed represent undiscounted cash flows on a gross basis, and no inflation elements have been applied.
Lease obligations. The Company’s total rental commitments under leases for office space and other property and equipment as of June 30, 2016 were $22.6 million.
Volume commitment agreements. As of June 30, 2016, the Company had certain agreements with an aggregate requirement to deliver or transport a minimum quantity of approximately 30.5 MMBbl of crude oil, 23.0 MMBbl of natural gas liquids and 220.6 Bcf of natural gas, prior to any applicable volume credits, within specified timeframes, all of which are ten years or less. The future commitments under certain agreements cannot be estimated as they are based on fixed differentials relative to WTI under the agreements as compared to the differential relative to WTI for the Williston Basin for the production month. The estimable future commitments under these agreements were approximately $442.0 million as of June 30, 2016.
Purchase agreements. As of June 30, 2016, the Company had certain agreements for the purchase of fresh water with an aggregate future commitment of approximately $38.8 million.
Litigation. The Company is party to various legal and/or regulatory proceedings from time to time arising in the ordinary course of business. While the ultimate outcome and impact to the Company cannot be predicted with certainty, the Company believes that all such matters are without merit and involve amounts which, if resolved unfavorably, either individually or in the aggregate, will not have a material adverse effect on its financial condition, results of operations or cash flows. 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.

16. Condensed Consolidating Financial Information
The Notes (see Note 8 – 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, 2016
 
Parent/
Issuer
 
Combined
Guarantor
Subsidiaries
 
Intercompany
Eliminations
 
Consolidated
 
(In thousands)
ASSETS
 
 
 
 
 
 
 
Current assets
 
 
 
 
 
 
 
Cash and cash equivalents
$
85

 
$
6,390

 
$
—

 
$
6,475

Accounts receivable – oil and gas revenues
—

 
109,121

 
—

 
109,121

Accounts receivable – joint interest and other
—

 
81,291

 
—

 
81,291

Accounts receivable – affiliates
1,348

 
198,702

 
(200,050
)
 
—

Inventory
—

 
9,018

 
—

 
9,018

Prepaid expenses
—

 
5,838

 
—

 
5,838

Derivative instruments
—

 
10,330

 
—

 
10,330

Other current assets
—

 
4,164

 
—

 
4,164

Total current assets
1,433

 
424,854

 
(200,050
)
 
226,237

Property, plant and equipment
 
 
 
 
 
 
 
Oil and gas properties (successful efforts method)
—

 
6,402,648

 
—

 
6,402,648

Other property and equipment
—

 
536,462

 
—

 
536,462

Less: accumulated depreciation, depletion, amortization and impairment
—

 
(1,752,376
)
 
—

 
(1,752,376
)
Total property, plant and equipment, net
—

 
5,186,734

 
—

 
5,186,734

Investments in and advances to subsidiaries
4,474,390

 
—

 
(4,474,390
)
 
—

Derivative instruments
—

 
64

 
—

 
64

Deferred income taxes
223,269

 
—

 
(223,269
)
 
—

Other assets
—

 
22,504

 
—

 
22,504

Total assets
$
4,699,092

 
$
5,634,156

 
$
(4,897,709
)
 
$
5,435,539

LIABILITIES AND EQUITY
 
 
 
 
 
 
 
Current liabilities
 
 
 
 
 
 
 
Accounts payable
$
—

 
$
10,357

 
$
—

 
$
10,357

Accounts payable – affiliates
198,702

 
1,348

 
(200,050
)
 
—

Revenues and production taxes payable
—

 
138,451

 
—

 
138,451

Accrued liabilities
31

 
128,253

 
—

 
128,284

Accrued interest payable
47,643

 
28

 
—

 
47,671

Derivative instruments
—

 
20,891

 
—

 
20,891

Advances from joint interest partners
—

 
5,416

 
—

 
5,416

Other current liabilities
—

 
15,001

 
—

 
15,001

Total current liabilities
246,376

 
319,745

 
(200,050
)
 
366,071

Long-term debt
2,092,361

 
35,000

 
—

 
2,127,361

Deferred income taxes
—

 
751,297

 
(223,269
)
 
528,028

Asset retirement obligations
—

 
36,390

 
—

 
36,390

Derivative instruments
—

 
14,291

 
—

 
14,291

Other liabilities
—

 
3,043

 
—

 
3,043

Total liabilities
2,338,737

 
1,159,766

 
(423,319
)
 
3,075,184

Stockholders’ equity
 
 
 
 
 
 
 
Capital contributions from affiliates
—

 
3,380,427

 
(3,380,427
)
 
—

Common stock, $0.01 par value: 450,000,000 shares authorized; 181,200,581 shares issued and 180,399,060 shares outstanding
1,777

 
—

 
—

 
1,777

Treasury stock, at cost: 801,521 shares
(15,140
)
 
—

 
—

 
(15,140
)
Additional paid-in-capital
1,693,583

 
8,743

 
(8,743
)
 
1,693,583

Retained earnings
680,135

 
1,085,220

 
(1,085,220
)
 
680,135

Total stockholders’ equity
2,360,355

 
4,474,390

 
(4,474,390
)
 
2,360,355

Total liabilities and stockholders’ equity
$
4,699,092

 
$
5,634,156

 
$
(4,897,709
)
 
$
5,435,539


18
Table of Contents

Condensed Consolidating Balance Sheet
 
December 31, 2015
 
Parent/
Issuer
 
Combined
Guarantor
Subsidiaries
 
Intercompany
Eliminations
 
Consolidated
 
(In thousands)
ASSETS
 
 
 
 
 
 
 
Current assets
 
 
 
 
 
 
 
Cash and cash equivalents
$
777

 
$
8,953

 
$
—

 
$
9,730

Accounts receivable – oil and gas revenues
—

 
96,495

 
—

 
96,495

Accounts receivable – joint interest and other
15

 
100,899

 
—

 
100,914

Accounts receivable – affiliates
1,248

 
247,488

 
(248,736
)
 
—

Inventory
—

 
11,072

 
—

 
11,072

Prepaid expenses
278

 
7,050

 
—

 
7,328

Derivative instruments
—

 
139,697

 
—

 
139,697

Other current assets
—

 
50

 
—

 
50

Total current assets
2,318

 
611,704

 
(248,736
)
 
365,286

Property, plant and equipment
 
 
 
 
 
 
 
Oil and gas properties (successful efforts method)
—

 
6,284,401

 
—

 
6,284,401

Other property and equipment
—

 
443,265

 
—

 
443,265

Less: accumulated depreciation, depletion, amortization and impairment
—

 
(1,509,424
)
 
—

 
(1,509,424
)
Total property, plant and equipment, net
—

 
5,218,242

 
—

 
5,218,242

Assets held for sale
—

 
26,728

 
—

 
26,728

Investments in and advances to subsidiaries
4,573,172

 
—

 
(4,573,172
)
 
—

Derivative instruments
—

 
15,776

 
—

 
15,776

Deferred income taxes
205,174

 
—

 
(205,174
)
 
—

Other assets
100

 
23,243

 
—

 
23,343

Total assets
$
4,780,764

 
$
5,895,693

 
$
(5,027,082
)
 
$
5,649,375

LIABILITIES AND EQUITY
 
 
 
 
 
 
 
Current liabilities
 
 
 
 
 
 
 
Accounts payable
$
—

 
$
9,983

 
$
—

 
$
9,983

Accounts payable – affiliates
247,488

 
1,248

 
(248,736
)
 
—

Revenue and production taxes payable
—

 
132,356

 
—

 
132,356

Accrued liabilities
10

 
167,659

 
—

 
167,669

Accrued interest payable
49,340

 
73

 
—

 
49,413

Advances from joint interest partners
—

 
4,647

 
—

 
4,647

Other current liabilities
—

 
6,500

 
—

 
6,500

Total current liabilities
296,838

 
322,466

 
(248,736
)
 
370,568

Long-term debt
2,164,584

 
138,000

 
—

 
2,302,584

Deferred income taxes
—

 
813,329

 
(205,174
)
 
608,155

Asset retirement obligations
—

 
35,338

 
—

 
35,338

Liabilities held for sale
—

 
10,228

 
—

 
10,228

Other liabilities
—

 
3,160

 
—

 
3,160

Total liabilities
2,461,422

 
1,322,521

 
(453,910
)
 
3,330,033

Stockholders’ equity
 
 
 
 
 
 
 
Capital contributions from affiliates
—

 
3,369,895

 
(3,369,895
)
 
—

Common stock, $0.01 par value: 300,000,000 shares authorized; 139,583,990 shares issued and 139,076,064 shares outstanding
1,376

 
—

 
—

 
1,376

Treasury stock, at cost: 507,926 shares
(13,620
)
 
—

 
—

 
(13,620
)
Additional paid-in-capital
1,497,065

 
8,743

 
(8,743
)
 
1,497,065

Retained earnings
834,521

 
1,194,534

 
(1,194,534
)
 
834,521

Total stockholders’ equity
2,319,342

 
4,573,172

 
(4,573,172
)
 
2,319,342

Total liabilities and stockholders’ equity
$
4,780,764

 
$
5,895,693

 
$
(5,027,082
)
 
$
5,649,375


19
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

Well services and midstream revenues
—

 
19,743

 
—

 
19,743

Total revenues
—

 
179,080

 
—

 
179,080

Operating expenses
 
 
 
 
 
 
 
Lease operating expenses
—

 
31,523

 
—

 
31,523

Well services and midstream operating expenses
—

 
8,875

 
—

 
8,875

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 income (expense)
—

 
(32
)
 
—

 
(32
)
Total other income (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
)




20
Table of Contents

Condensed Consolidating Statement of Operations
 
Three Months Ended June 30, 2015
 
Parent/
Issuer
 
Combined
Guarantor
Subsidiaries
 
Intercompany
Eliminations
 
Consolidated
 
(In thousands)
Revenues
 
 
 
 
 
 
 
Oil and gas revenues
$
—

 
$
214,110

 
$
—

 
$
214,110

Well services and midstream revenues
—

 
15,936

 
—

 
15,936

Total revenues
—

 
230,046

 
—

 
230,046

Operating expenses
 
 
 
 
 
 
 
Lease operating expenses
—

 
37,761

 
—

 
37,761

Well services and midstream operating expenses
—

 
7,395

 
—

 
7,395

Marketing, transportation and gathering expenses
—

 
7,570

 
—

 
7,570

Production taxes
—

 
20,618

 
—

 
20,618

Depreciation, depletion and amortization
—

 
119,218

 
—

 
119,218

Exploration expenses
—

 
1,082

 
—

 
1,082

Rig termination
—

 
2,815

 
—

 
2,815

Impairment
—

 
19,516

 
—

 
19,516

General and administrative expenses
6,325

 
15,183

 
—

 
21,508

Total operating expenses
6,325

 
231,158

 
—

 
237,483

Operating loss
(6,325
)
 
(1,112
)
 
—

 
(7,437
)
Other income (expense)
 
 
 
 
 
 
 
Equity in loss of subsidiaries
(34,249
)
 
—

 
34,249

 
—

Net loss on derivative instruments
—

 
(39,424
)
 
—

 
(39,424
)
Interest expense, net of capitalized interest
(34,194
)
 
(3,211
)
 
—

 
(37,405
)
Other income
5

 
186

 
—

 
191

Total other income (expense)
(68,438
)
 
(42,449
)
 
34,249

 
(76,638
)
Loss before income taxes
(74,763
)
 
(43,561
)
 
34,249

 
(84,075
)
Income tax benefit
21,533

 
9,312

 
—

 
30,845

Net loss
$
(53,230
)
 
$
(34,249
)
 
$
34,249

 
$
(53,230
)


21
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

Well services and midstream revenues
—

 
32,711

 
—

 
32,711

Total revenues
—

 
309,363

 
—

 
309,363

Operating expenses
 
 
 
 
 
 
 
Lease operating expenses
—

 
62,587

 
—

 
62,587

Well services and midstream operating expenses
—

 
13,264

 
—

 
13,264

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

Rig termination
—

 
—

 
—

 
—

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 income (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
)


22
Table of Contents

Condensed Consolidating Statement of Operations
 
Six Months Ended June 30, 2015
 
Parent/
Issuer
 
Combined
Guarantor
Subsidiaries
 
Intercompany
Eliminations
 
Consolidated
 
(In thousands)
Revenues
 
 
 
 
 
 
 
Oil and gas revenues
$
—

 
$
387,969

 
$
—

 
$
387,969

Well services and midstream revenues
—

 
22,464

 
—

 
22,464

Total revenues
—

 
410,433

 
—

 
410,433

Operating expenses
 
 
 
 
 
 
 
Lease operating expenses
—

 
76,886

 
—

 
76,886

Well services and midstream operating expenses
—

 
9,347

 
—

 
9,347

Marketing, transportation and gathering expenses
—

 
14,848

 
—

 
14,848

Production taxes
—

 
37,239

 
—

 
37,239

Depreciation, depletion and amortization
—

 
237,696

 
—

 
237,696

Exploration expenses
—

 
1,925

 
—

 
1,925

Rig termination
—

 
3,895

 
—

 
3,895

Impairment
—

 
24,837

 
—

 
24,837

General and administrative expenses
14,944

 
29,888

 
—

 
44,832

Total operating expenses
14,944

 
436,561

 
—

 
451,505

Operating loss
(14,944
)
 
(26,128
)
 
—

 
(41,072
)
Other income (expense)
 
 
 
 
 
 
 
Equity in loss of subsidiaries
(21,630
)
 
—

 
21,630

 
—

Net gain on derivative instruments
—

 
7,648

 
—

 
7,648

Interest expense, net of capitalized interest
(69,415
)
 
(6,774
)
 
—

 
(76,189
)
Other income
4

 
117

 
—

 
121

Total other income (expense)
(91,041
)
 
991

 
21,630

 
(68,420
)
Loss before income taxes
(105,985
)
 
(25,137
)
 
21,630

 
(109,492
)
Income tax benefit
34,714

 
3,507

 
—

 
38,221

Net loss
$
(71,271
)
 
$
(21,630
)
 
$
21,630

 
$
(71,271
)



23
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 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 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:
 
 
 
 
 
 
 
Repurchase of senior unsecured notes
(56,925
)
 
—

 
—

 
(56,925
)
Proceeds from revolving credit facility
—

 
359,000

 
—

 
359,000

Principal payments on revolving credit facility
—

 
(462,000
)
 
—

 
(462,000
)
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



24
Table of Contents

Condensed Consolidating Statement of Cash Flows
 
Six Months Ended June 30, 2015
 
Parent/
Issuer
 
Combined
Guarantor
Subsidiaries
 
Intercompany
Eliminations
 
Consolidated
 
(In thousands)
Cash flows from operating activities:
 
 
 
 
 
 
 
Net loss
$
(71,271
)
 
$
(21,630
)
 
$
21,630

 
$
(71,271
)
Adjustments to reconcile net loss to cash provided by (used in) operating activities:
 
 
 
 
 
 
 
Equity in loss of subsidiaries
21,630

 
—

 
(21,630
)
 
—

Depreciation, depletion and amortization
—

 
237,696

 
—

 
237,696

Impairment
—

 
24,837

 
—

 
24,837

Deferred income taxes
(34,714
)
 
(3,507
)
 
—

 
(38,221
)
Derivative instruments
—

 
(7,648
)
 
—

 
(7,648
)
Stock-based compensation expenses
13,515

 
148

 
—

 
13,663

Deferred financing costs amortization and other
2,255

 
2,804

 
—

 
5,059

Working capital and other changes:
 
 
 
 
 
 
 
Change in accounts receivable
(256
)
 
9,890

 
66,165

 
75,799

Change in inventory
—

 
3,685

 
—

 
3,685

Change in prepaid expenses
297

 
3,097

 
—

 
3,394

Change in other current assets
—

 
5,538

 
—

 
5,538

Change in accounts payable, interest payable and accrued liabilities
65,933

 
(22,392
)
 
(66,165
)
 
(22,624
)
Change in other liabilities
—

 
(21
)
 
—

 
(21
)
Net cash provided by (used in) operating activities
(2,611
)
 
232,497

 
—

 
229,886

Cash flows from investing activities:
 
 
 
 
 
 
 
Capital expenditures
—

 
(587,430
)
 
—

 
(587,430
)
Derivative settlements
—

 
213,336

 
—

 
213,336

Advances from joint interest partners
—

 
(406
)
 
—

 
(406
)
Net cash used in investing activities
—

 
(374,500
)
 
—

 
(374,500
)
Cash flows from financing activities:
 
 
 
 
 
 
 
Proceeds from revolving credit facility
—

 
320,000

 
—

 
320,000

Principal payments on revolving credit facility
—

 
(665,000
)
 
—

 
(665,000
)
Deferred financing costs
—

 
(3,591
)
 
—

 
(3,591
)
Proceeds from sale of common stock
463,010

 
—

 
—

 
463,010

Purchases of treasury stock
(1,932
)
 
—

 
—

 
(1,932
)
Investment in / capital contributions from subsidiaries
(458,465
)
 
458,465

 
—

 
—

Net cash provided by financing activities
2,613

 
109,874

 
—

 
112,487

Increase (decrease) in cash and cash equivalents
2

 
(32,129
)
 
—

 
(32,127
)
Cash and cash equivalents at beginning of period
776

 
45,035

 
—

 
45,811

Cash and cash equivalents at end of period
$
778

 
$
12,906

 
$
—

 
$
13,684


25
Table of Contents

17. 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 2016, the Company entered into a three-way costless collar agreement with a floor price of $45.00 per barrel for total notional amounts of 334,000 barrels and 31,000 barrels, which settle in 2017 and 2018, respectively, based on WTI. These derivative instruments do not qualify for and were not designated as hedging instruments for accounting purposes.
Credit facility amendment. On August 8, 2016, the Company entered into its sixth amendment to its Credit Facility (the “Sixth Amendment”), which provides the Company with more flexibility in raising new capital and refinancing its existing Notes. The Sixth Amendment did not change the Company’s current borrowing base and aggregate elected commitment of $1,150.0 million. The next regular semi-annual redetermination of the borrowing base is scheduled for October 1, 2016.


26
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, 2015 (“2015 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 Item 1A. “Risk Factors” in our 2015 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 well services company;
•
owning, operating and developing a midstream company;
•
infrastructure for salt water disposal;
•
gathering, transportation and marketing of oil and natural gas, both in the Williston Basin and other regions in the United States;
•
property acquisitions;
•
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;
•
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

27
Table of Contents

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 well services business through Oasis Well Services LLC (“OWS”) and a midstream services business through Oasis Midstream Services LLC (“OMS”), 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 OWS and OMS 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. We intend to continue to acquire both operated and non-operated properties to the extent we believe they meet our return objectives. 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.
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. The current global oversupply of crude oil has caused a sharp decline in oil prices since mid-2014. As a result of sustained low oil prices, we have decreased our planned 2016 capital expenditures as compared to 2015, and we are continuing to concentrate our drilling activities in certain areas that are the most economic in the Williston Basin. 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 sales contracts with purchasers who have access to crude oil 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

28
Table of Contents

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. As of June 30, 2016, we were flowing 83% of our gross operated oil production through these gathering systems.
Our market optionality on the crude oil gathering systems allows us to shift volumes between pipeline and rail markets in order to optimize price realizations. Crude oil produced and sold in the Williston Basin has historically sold at a discount to the NYMEX West Texas Intermediate crude oil index prices (“WTI”) due to transportation costs and takeaway capacity. In the past, there have been periods when this discount has substantially increased due to oil production in the area increasing to a point that it temporarily surpassed the available pipeline transportation, rail transportation and refining capacity in the area. Expansions of both rail and pipeline facilities have reduced the prior constraint on oil transportation out of the Williston Basin and improved our price differentials received at the lease. In 2015, our price differentials relative to WTI strengthened as new pipelines opened to eastern Canada and U.S. markets and transportation on rail gradually declined. Since the third quarter of 2015, our price differentials have remained less than $5.00 per barrel discount to WTI on a quarterly basis. Even as WTI improved in the first half of 2016, our price differentials averaged $4.85 per barrel of oil.
Forward commodity prices and estimates of future production play a significant role in determining impairment of proved oil and natural gas properties. As a result of lower commodity prices and their impact on our estimated future cash flows, we have continued to monitor our proved oil and natural gas properties for impairment. For the six months ended June 30, 2016, we recorded an impairment charge of $3.6 million to further write down our properties held for sale to their fair value, as determined by the sales price on April 1, 2016, less costs to sell. No other proved impairment charges were recorded during the six months ended June 30, 2016. In addition, the excess of our expected undiscounted future cash flows over the carrying value of our proved oil and natural gas properties in the Bakken and Three Forks formations has increased to $1,978.3 million as of June 30, 2016, an increase of approximately 56% as compared to an excess of $1,264.8 million at December 31, 2015. The underlying commodity prices embedded in our expected undiscounted cash flows were determined using NYMEX forward strip prices for five years, escalating 3% per year thereafter. Our expected undiscounted estimated cash flows also included a 3% inflation factor applied to the future operating and development costs after five years. If expected future oil prices decline by approximately 20% as compared to June 30, 2016, holding all other factors constant, the expected undiscounted cash flows may not exceed the carrying value of our proved oil and natural gas properties in the Bakken and Three Forks formations. As a result, we may recognize additional proved impairment charges in the future, and such impairment charges could exceed $2.3 billion assuming a discount rate of 10%.
Changes in commodity prices may significantly impact our estimates of oil and natural gas reserves, which are estimated and reported as of December 31 of each calendar year. Our estimated net proved reserves at December 31, 2015 were prepared using SEC pricing, calculated as the unweighted arithmetic average first-day-of-the-month prices for the prior twelve months of $50.16 per barrel for oil and $2.63 per MMBtu for natural gas. The current forward commodity price curve is lower than the year-end 2015 SEC pricing; therefore, the following sensitivity table is provided to illustrate the estimated impact of this price decrease on our estimated proved reserves, PV-10 and Standardized Measure. In addition to the different price assumptions, the sensitivity case below includes assumed capital and expense reductions we expect to realize at lower commodity prices. The reduction in proved developed reserves is attributable to reaching the economic limit sooner. The reduction in proved undeveloped reserves is a result of well locations no longer meeting our investment criteria as well as reaching the economic limit sooner. This sensitivity case is only to demonstrate the impact that a lower price and cost environment would have had on estimated proved reserves, PV-10 and Standardized Measure as of December 31, 2015, holding all other factors constant. There is no assurance that these prices or assumed cost savings will actually be achieved. Our estimated net proved reserves, PV-10 and Standardized Measure were determined using prices for oil and natural gas, without giving effect to derivative transactions, which were held constant throughout the life of the properties. The prices were adjusted by lease for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead.

29
Table of Contents

 
Actual at December 31, 2015(1)
 
Sensitivity Case(2)
Oil price (per Bbl)
$
50.16

 
$
44.19

Natural gas price (per MMBtu)
2.63

 
2.52

 
 
 
 
Capital expenditure reduction
n/a

 
15%

Operating expense reduction
n/a

 
16%

 
 
 
 
Estimated proved developed reserves (MMBoe)
147.6

 
149.6

Estimated proved undeveloped reserves (MMBoe)
70.7

 
71.4

Total estimated proved reserves (MMBoe)
$
218.2

 
$
221.0

 
 
 
 
PV-10 (in millions)(3)
$
2,022.7

 
$
1,866.4

Present value of future income taxes discounted at 10% (in millions)
108.4

 
60.1

Standardized Measure of discounted future net cash flows (in millions)(4)
$
1,914.3

 
$
1,806.3

__________________ 
(1)
The actual reserve estimates at December 31, 2015 were prepared using SEC pricing, calculated as the unweighted arithmetic average first-day-of-the-month prices for the prior twelve months, which was $50.16 per barrel for oil and $2.63 per MMBtu for natural gas for the year ended December 31, 2015.
(2)
The sensitivity case prices represent potential SEC pricing based on actual prices for each of the six months ended June 30, 2016 and forward commodity prices as of June 30, 2016 for the remaining months of 2016.
(3)
PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable financial measure under accounting principles generally accepted in the United States of America (“GAAP”), because it does not include the effect of income taxes on discounted future net cash flows. Neither PV-10 nor Standardized Measure represents an estimate of the fair market value of our oil and natural gas reserves. The oil and gas industry uses PV-10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific tax characteristics of such entities.
(4)
Standardized Measure represents the present value of estimated future net cash flows from proved oil and natural gas reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reflect timing of future cash flows.
Second Quarter 2016 Highlights:
•
Average daily production was 49,507 Boe per day during the three months ended June 30, 2016;
•
We completed and placed on production 13 gross (8.7 net) operated wells in the Williston Basin during the three months ended June 30, 2016;
•
For the three months ended June 30, 2016, total capital expenditures were $131.3 million;
•
At June 30, 2016, we had $6.5 million of cash and cash equivalents and had total liquidity of $1,107.3 million, including the availability under our revolving credit facility;
•
Net cash provided by operating activities was $91.4 million for the three months ended June 30, 2016. Adjusted EBITDA, a non-GAAP financial measure, was $132.2 million for the three months ended June 30, 2016. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to net loss 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 well services and midstream revenues are primarily derived from well services, product sales, equipment rentals, salt water pipeline transport, salt water disposal and fresh water sales for third-party working interest owners in OPNA’s operated wells. Intercompany revenues for work performed by OWS and OMS for OPNA’s working interests are eliminated in consolidation.

30
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,
 
2016
 
2015
 
Change
 
2016
 
2015
 
Change
Operating results (in thousands):
 
 
 
 
 
 
 
 
 
 
 
Revenues
 
 
 
 
 
 
 
 
 
 
 
Oil
$
152,900

 
$
208,564

 
$
(55,664
)
 
$
264,106

 
$
372,377

 
$
(108,271
)
Natural gas
6,437

 
5,546

 
891

 
12,546

 
15,592

 
(3,046
)
Well services
12,833

 
9,219

 
3,614

 
18,818

 
11,927

 
6,891

Midstream
6,910

 
6,717

 
193

 
13,893

 
10,537

 
3,356

Total revenues
$
179,080

 
$
230,046

 
$
(50,966
)
 
$
309,363

 
$
410,433

 
$
(101,070
)
Production data:
 
 
 
 
 
 
 
 
 
 
 
Oil (MBbls)
3,747

 
4,008

 
(261
)
 
7,617

 
8,030

 
(413
)
Natural gas (MMcf)
4,549

 
3,395

 
1,154

 
8,802

 
6,502

 
2,300

Oil equivalents (MBoe)
4,505

 
4,574

 
(69
)
 
9,084

 
9,114

 
(30
)
Average daily production (Boe per day)
49,507

 
50,261

 
(754
)
 
49,911

 
50,353

 
(442
)
Average sales prices:
 
 
 
 
 
 
 
 
 
 
 
Oil, without derivative settlements (per Bbl)
$
40.81

 
$
52.04

 
$
(11.23
)
 
$
34.67

 
$
46.37

 
$
(11.70
)
Oil, with derivative settlements (per Bbl)(1)
48.94

 
78.01

 
(29.07
)
 
48.30

 
72.94

 
(24.64
)
Natural gas (per Mcf)(2)
1.42

 
1.63

 
(0.21
)
 
1.43

 
2.40

 
(0.97
)
____________________
(1)
Realized prices include gains or losses on cash settlements for commodity derivatives, which do not qualify for and 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, 2016 as compared to three months ended June 30, 2015
Total revenues. Our total revenues decreased $51.0 million, or 22%, to $179.1 million during the three months ended June 30, 2016 as compared to the three months ended June 30, 2015, primarily due to lower realized oil sales prices. Our average realized prices for oil decreased by 22% during the three months ended June 30, 2016 as compared to the three months ended June 30, 2015.
Oil and gas revenues. Our primary revenues are a function of oil and natural gas production volumes sold and average sales prices received for those volumes. Average daily production sold decreased by 754 Boe per day to 49,507 Boe per day during the three months ended June 30, 2016 as compared to the three months ended June 30, 2015. The decrease in average daily production sold was primarily a result of the natural decline in production in wells that were producing as of June 30, 2015 coupled with the divestiture completed on April 1, 2016 (see Note 7 to our condensed consolidated financial statements), offset by our 48.4 total net well completions in the Williston Basin during the twelve months ended June 30, 2016. The divestiture resulted in a decrease in average daily production of approximately 671 Boe per day during the three months ended June 30, 2016. Average oil sales prices, without derivative settlements, decreased by $11.23 per barrel to an average of $40.81 per barrel, and average natural gas sales prices, which include the value for natural gas and natural gas liquids, decreased by $0.21 per Mcf to an average of $1.42 per Mcf for the three months ended June 30, 2016 as compared to the three months ended June 30, 2015. The lower oil and natural gas sales prices decreased revenues by $45.8 million, coupled with lower total production amounts sold, which decreased revenues by $9.0 million during the three months ended June 30, 2016 as compared to the three months ended June 30, 2015. Extended low commodity prices could result in a significant decrease in our oil and gas volumes and revenues in the future.
Well services and midstream 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. While our well completion activity decreased, our well services revenues increased by $3.6 million to $12.8 million for the three months ended June 30, 2016 as compared to the three months ended June 30, 2015 primarily due to a $3.5 million increase in well completion revenues as a result of OWS completing OPNA wells with a higher average third-party working interest during the three months ended June 30, 2016. Midstream revenues remained relatively consistent at $6.9 million and $6.7 million for the three months ended June 30, 2016 and 2015, respectively.

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Table of Contents

Six months ended June 30, 2016 as compared to six months ended June 30, 2015
Our total revenues decreased $101.1 million, or 25%, to $309.4 million during the six months ended June 30, 2016 as compared to the six months ended June 30, 2015, primarily due to lower realized oil and natural gas sales prices. Our average realized prices for oil and natural gas decreased by 25% and 40%, respectively, during the six months ended June 30, 2016 as compared to the six months ended June 30, 2015.
Oil and gas revenues. Our primary revenues are a function of oil and natural gas production volumes sold and average sales prices received for those volumes. Average daily production sold decreased by 442 Boe per day, or 1%, to 49,911 Boe per day during the six months ended June 30, 2016 as compared to the six months ended June 30, 2015. The decrease in average daily production sold was primarily a result of the decline in production in wells that were producing as of June 30, 2015 coupled with the divestiture completed on April 1, 2016 (see Note 7 to our condensed consolidated financial statements), offset by our 48.4 total net well completions in the Williston Basin during the twelve months ended June 30, 2016. The divestiture resulted in a decrease in average daily production of approximately 438 Boe per day during the six months ended June 30, 2016. Average oil sales prices, without derivatives settlements, decreased by $11.70 per barrel to an average of $34.67 per barrel, and average natural gas sales prices, which include the value for natural gas and natural gas liquids, decreased by $0.97 per Mcf to an average of $1.43 per Mcf for the six months ended June 30, 2016 as compared to the six months ended June 30, 2015. The lower oil and natural gas sales prices decreased revenues by $100.3 million, coupled with lower total production amounts sold, which decreased revenues by $11.1 million during the six months ended June 30, 2016 as compared to the six months ended June 30, 2015.
Well services and midstream 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. While our well completion activity decreased, our well services revenues increased $6.9 million to $18.8 million for the six months ended June 30, 2016 as compared to the six months ended June 30, 2015 primarily due to an increase of $9.0 million in well completion revenue as a result of OWS completing OPNA wells with a higher average third-party working interest, offset by a $1.5 million decrease in well completion product sales to third parties as a result of OWS completing all of OPNA’s operated wells during the six months ended June 30, 2016. Midstream revenues were $13.9 million for the six months ended June 30, 2016, which was a $3.4 million increase period over period, primarily due to increased water volumes flowing through our salt water disposal systems, offset by decreased fresh water sales.


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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,
 
2016
 
2015
 
Change
 
2016
 
2015
 
Change
 
(In thousands, except per Boe of production)
Operating expenses:
 
 
 
 
 
 
 
 
 
 
 
Lease operating expenses
$
31,523

 
$
37,761

 
$
(6,238
)
 
$
62,587

 
$
76,886

 
$
(14,299
)
Well services and midstream operating expenses
8,875

 
7,395

 
1,480

 
13,264

 
9,347

 
3,917

Marketing, transportation and gathering expenses
6,491

 
7,570

 
(1,079
)
 
15,043

 
14,848

 
195

Production taxes
14,367

 
20,618

 
(6,251
)
 
25,120

 
37,239

 
(12,119
)
Depreciation, depletion and amortization
122,488

 
119,218

 
3,270

 
244,937

 
237,696

 
7,241

Exploration expenses
340

 
1,082

 
(742
)
 
703

 
1,925

 
(1,222
)
Rig termination
—

 
2,815

 
(2,815
)
 
—

 
3,895

 
(3,895
)
Impairment
23

 
19,516

 
(19,493
)
 
3,585

 
24,837

 
(21,252
)
General and administrative expenses
21,876

 
21,508

 
368

 
46,242

 
44,832

 
1,410

Total operating expenses
205,983

 
237,483

 
(31,500
)
 
411,481

 
451,505

 
(40,024
)
Loss on sale of properties
(1,311
)
 
—

 
(1,311
)
 
(1,311
)
 
—

 
(1,311
)
Operating loss
(28,214
)
 
(7,437
)
 
(20,777
)
 
(103,429
)
 
(41,072
)
 
(62,357
)
Other income (expense):
 
 
 
 
 
 
 
 
 
 
 
Net gain (loss) on derivative instruments
(90,846
)
 
(39,424
)
 
(51,422
)
 
(76,471
)
 
7,648

 
(84,119
)
Interest expense, net of capitalized interest
(34,979
)
 
(37,405
)
 
2,426

 
(73,718
)
 
(76,189
)
 
2,471

Gain on extinguishment of debt
11,642

 
—

 
11,642

 
18,658

 
—

 
18,658

Other income (expense)
(32
)
 
191

 
(223
)
 
447

 
121

 
326

Total other income (expense)
(114,215
)
 
(76,638
)
 
(37,577
)
 
(131,084
)
 
(68,420
)
 
(62,664
)
Loss before income taxes
(142,429
)
 
(84,075
)
 
(58,354
)
 
(234,513
)
 
(109,492
)
 
(125,021
)
Income tax benefit
52,498

 
30,845

 
21,653

 
80,127

 
38,221

 
41,906

Net loss
$
(89,931
)
 
$
(53,230
)
 
$
(36,701
)
 
$
(154,386
)
 
$
(71,271
)
 
$
(83,115
)
Costs and expenses (per Boe of production):
 
 
 
 
 
 
 
 
 
 
 
Lease operating expenses
$
7.00

 
$
8.26

 
$
(1.26
)
 
$
6.89

 
$
8.44

 
$
(1.55
)
Marketing, transportation and gathering expenses
1.44

 
1.66

 
(0.22
)
 
1.66

 
1.63

 
0.03

Production taxes
3.19

 
4.51

 
(1.32
)
 
2.77

 
4.09

 
(1.32
)
Depreciation, depletion and amortization
27.19

 
26.07

 
1.12

 
26.96

 
26.08

 
0.88

General and administrative expenses
4.86

 
4.70

 
0.16

 
5.09

 
4.92

 
0.17


Three months ended June 30, 2016 as compared to three months ended June 30, 2015
Lease operating expenses. Lease operating expenses decreased $6.2 million to $31.5 million for the three months ended June 30, 2016 as compared to the three months ended June 30, 2015. This decrease was primarily due to an increase in salt water disposal volumes being transported on OMS pipelines and injected in OMS salt water disposal wells coupled with a decrease in our net well count as a result of the divestiture completed on April 1, 2016 (see Note 7 to our condensed consolidated financial statements). Lease operating expenses decreased from $8.26 per Boe for the three months ended June 30, 2015 to $7.00 per Boe for the three months ended June 30, 2016.
Well services and midstream operating expenses. Well services and midstream operating expenses represent third-party working interest owners’ share of service costs, cost of goods sold and operating expenses incurred by OWS and OMS. The $1.5 million increase for the three months ended June 30, 2016 as compared to the three months ended June 30, 2015 was primarily attributable to a $1.8 million increase in well completion costs as a result of OWS completing OPNA wells with a higher average third-party working interest. This increase was offset by a decrease in midstream operating expenses of $0.3

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million during the three months ended June 30, 2016 as compared to the three months ended June 30, 2015 due to decreased fresh water purchases.
Marketing, transportation and gathering expenses. The $1.1 million decrease in marketing, transportation and gathering expenses for the three months ended June 30, 2016 as compared to the three months ended June 30, 2015 was primarily attributable to a $0.5 million decrease in oil transportation costs and a $0.4 million decrease in our pipeline imbalance.
Production taxes. Our production taxes as a percentage of oil and natural gas sales were 9.0% and 9.6%, respectively, for the three months ended June 30, 2016 and 2015. The production tax rate decreased period over period primarily due to the reduction in the North Dakota oil extraction tax rate, partially offset by an increased weighting of production in North Dakota, which has a higher average production tax rate as compared to Montana. For the three months ended June 30, 2016 and 2015, the percentage of our total production located in North Dakota was 92% and 87%, respectively. In 2015, North Dakota had a crude oil tax structure based on a 5% production tax and a 6.5% oil extraction tax, resulting in a combined tax rate of 11.5% of crude oil revenues. In 2016, the North Dakota oil extraction tax was reduced to 5%, resulting in a combined tax rate of 10% of crude oil revenues.
Depreciation, depletion and amortization (“DD&A”). DD&A expense increased $3.3 million to $122.5 million for the three months ended June 30, 2016 as compared to the three months ended June 30, 2015. This increase in DD&A expense for the three months ended June 30, 2016 was a result of an increase in the DD&A rate, offset by a decrease in total production during the six months ended June 30, 2016. The DD&A rate for the three months ended June 30, 2016 was $27.19 per Boe compared to $26.07 per Boe for the three months ended June 30, 2015. The increase in the DD&A rate was primarily due to lower proved reserves as a result of lower oil and natural gas prices.
Impairment. For the three months ended June 30, 2016 and 2015, we recorded non-cash impairment charges of $23,000 and $0.4 million, respectively, for unproved properties due to leases that expired in the period. As a result of periodic assessments of unproved properties not held-by-production, we recorded non-cash impairment charges on our unproved oil and natural gas properties of $19.1 million for the three months ended June 30, 2015 related to acreage expiring in future periods because there were no current plans to drill or extend the leases prior to their expiration. During the year ended December 31, 2015, we recorded similar non-cash impairment charges of $4.7 million related to leases that expired during the three months ended June 30, 2016 as a result of periodic assessments of unproved properties. Consequently, lower impairment charges for unproved properties were recorded during the three months ended June 30, 2016 as most leases that expired during the period had been previously impaired. No impairment charges of proved oil and gas properties were recorded for the three months ended June 30, 2016 and 2015.
General and administrative expenses (“G&A”). Our G&A increased $0.4 million to $21.9 million for the three months ended June 30, 2016 as compared to the three months ended June 30, 2015. G&A for our OWS segment increased by $2.6 million for the three months ended June 30, 2016 as compared to the three months ended June 30, 2015. The increase in OWS G&A was due to OWS completing OPNA wells with a higher average third-party working interest during the three months ended June 30, 2016 as compared to the three months ended June 30, 2015. Excluding our intercompany elimination, gross OWS G&A decreased $2.8 million. E&P G&A was $17.7 million and $19.8 million for the three months ended June 30, 2016 and 2015, respectively. These decreases in gross OWS and E&P G&A were primarily due to lower compensation expenses due to a decrease in employee headcount. Our total company full-time employee headcount decreased to 453 at June 30, 2016 from 567 at June 30, 2015.
Derivative instruments. As a result of entering into derivative contracts and the effect of the forward strip oil price changes, we incurred 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, and a $39.4 million net loss on derivative instruments, including net cash settlement receipts of $104.1 million, for the three months ended June 30, 2015. 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 $2.4 million from $37.4 million for the three months ended June 30, 2015 to $35.0 million for the three months ended June 30, 2016 due to a decrease in interest expense incurred on our senior unsecured notes and revolving credit facility during the three months ended June 30, 2016. In 2016, we repurchased an aggregate principal amount of $76.6 million of outstanding senior unsecured notes, which resulted in a decrease of $1.5 million in interest expense for the three months ended June 30, 2016. For the three months ended June 30, 2016 and 2015, the weighted average debt outstanding under our revolving credit facility was $82.7 million and $184.7 million, respectively. The weighted average interest rate incurred on the outstanding borrowings under our revolving credit facility was 2.0% and 1.7% for the three months ended June 30, 2016 and June 30, 2015, respectively. Interest capitalized during the three months ended June 30, 2016 and 2015 was $4.8 million and $4.9 million, respectively.

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Gain on extinguishment of debt. In April 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. For the three months ended June 30, 2015, we did not repurchase any portion of our outstanding senior unsecured notes.
Income taxes. The income tax benefit for the three months ended June 30, 2016 and 2015 was recorded at 36.9% and 36.7% of pre-tax net income, respectively. Our effective tax rates for the three months ended June 30, 2016 and 2015 approximate the combined federal statutory tax rate and the statutory rates for the states in which we conduct business.
Six months ended June 30, 2016 as compared to six months ended June 30, 2015
Lease operating expense. Lease operating expenses decreased $14.3 million to $62.6 million for the six months ended June 30, 2016 as compared to the six months ended June 30, 2015. The decrease was primarily due to an increase in salt water disposal volumes being transported on OMS pipelines and injected in OMS salt water disposal wells. Lease operating expenses decreased from $8.44 per Boe for the six months ended June 30, 2015 to $6.89 per Boe for the six months ended June 30, 2016.
Well services and midstream operating expenses. Well services and midstream operating expenses represent third-party working interest owners’ share of service costs, cost of goods sold and operating expenses incurred by OWS and OMS. The $3.9 million increase for the six months ended June 30, 2016 as compared to the six months ended June 30, 2015 was attributable to a $3.4 million increase due to OWS completing OPNA wells with a higher average third-party working interest in the six months ended June 30, 2016 as compared to the six months ended June 30, 2015. This increase was coupled with a $0.5 million increase in midstream operating expenses related to an increase in salt water disposal wells and pipelines in service.
Marketing, transportation and gathering expenses. The $0.2 million increase in marketing, transportation and gathering expenses for the six months ended June 30, 2016 as compared to the six months ended June 30, 2015 was primarily attributable to a $0.8 million increase in the pipeline imbalance, offset by a $0.9 million decrease in oil transportation costs.
Production taxes. Our production taxes as a percentage of oil and natural gas sales were 9.1% and 9.6%, respectively, for the six months ended June 30, 2016 and 2015. The production tax rate decreased period over period primarily due to the reduction in the North Dakota oil extraction tax rate, partially offset by an increased weighting of production in North Dakota, which has a higher average production tax rate as compared to Montana. For the six months ended June 30, 2016 and 2015, the percentage of our total production located in North Dakota was 91% and 87%, respectively. In 2015, North Dakota had a crude oil tax structure based on a 5% production tax and a 6.5% oil extraction tax, resulting in a combined tax rate of 11.5% of crude oil revenues. In 2016, the North Dakota oil extraction tax was reduced to 5%, resulting in a combined tax rate of 10% of crude oil revenues.
Depreciation, depletion, and amortization. DD&A expense increased $7.2 million to $244.9 million for the six months ended June 30, 2016 as compared to the six months ended June 30, 2015. The increase in DD&A expense for the six months ended June 30, 2016 was a result of an increase in the DD&A rate during the six months ended June 30, 2016. The DD&A rate for the six months ended June 30, 2016 was $26.96 per Boe compared to $26.08 per Boe for the six months ended June 30, 2015. The increase in the DD&A rate was primarily due to lower recoverable reserves related to lower oil and natural gas prices.
Impairment. During the six months ended June 30, 2016, we recorded an impairment charge of $3.6 million to further adjust the carrying value of our properties held for sale during the first quarter of 2016 to their estimated fair value, determined based on the expected sales price, less costs to sell. No impairment charges of proved oil and gas properties were recorded for the six months ended June 30, 2015. For the six months ended June 30, 2016 and 2015, we recorded non-cash impairment charges of $25,000 and $4.5 million, respectively, for unproved properties due to leases that expired during the period. As a result of periodic assessments of unproved properties not held-by-production, we recorded additional impairment charges of $20.3 million for the six months ended June 30, 2015 related to acreage expiring in future periods because there were no current plans to drill or extend the leases prior to their expiration. During the year ended December 31, 2015, we recorded similar non-cash impairment charges of $9.8 million related to leases that expired during the six months ended June 30, 2016 as a result of periodic assessments of unproved properties. Consequently, lower impairment charges for unproved properties were recorded during the six months ended June 30, 2016 as most leases that expired during the period had been previously impaired.
General and administrative expenses. Our G&A expenses increased $1.4 million for the six months ended June 30, 2016 from $44.8 million for the six months ended June 30, 2015. OWS G&A increased by $4.6 million primarily due to OWS completing OPNA wells with a higher average third-party working interest in the six months ended June 30, 2016 as compared

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to the six months ended June 30, 2015. Excluding our intercompany elimination, gross OWS G&A decreased $5.4 million. E&P G&A was $38.8 million and $42.1 million for the six months ended June 30, 2016 and 2015, respectively. These decreases in gross OWS and E&P G&A were primarily due to lower compensation expenses due to a decrease in employee headcount. Our total company full-time employee headcount decreased to 453 at June 30, 2016 from 567 at June 30, 2015.
Derivative instruments. As a result of entering into derivative contracts and the effect of the forward strip oil price changes, we incurred 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, and a $7.6 million net gain on derivative instruments, including net cash settlement receipts of $213.3 million for the six months ended June 30, 2015. 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 $2.5 million to $73.7 million for the six months ended June 30, 2016 as compared to the six months ended June 30, 2015. The decrease was primarily the result of a decrease in the interest expense incurred on borrowings under our revolving credit facility and senior unsecured notes, offset by an increase of $1.3 million due to the unamortized deferred financing costs write-off related to the decrease in the borrowing base under our revolving credit facility during the six months ended June 30, 2016. In 2016, we repurchased an aggregate principal amount of $76.6 million of outstanding senior unsecured notes, which resulted in a decrease of $1.8 million in interest expense for the six months ended June 30, 2016. For the six months ended June 30, 2016 and 2015, the weighted average debt outstanding under our revolving credit facility was $94.8 million and $318.8 million, respectively, and the weighted average interest rate incurred on the outstanding borrowings was 1.9% and 1.8%, respectively. Interest capitalized during the six months ended June 30, 2016 and 2015 was $9.3 million and $8.8 million, respectively. The increase in interest capitalized period over period was due to increased work in progress assets, including the natural gas processing plant and other midstream infrastructure we are constructing in Wild Basin.
Gain on extinguishment of debt. 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. During the six months ended June 30, 2015, we did not repurchase any portion of our outstanding senior unsecured notes.
Income taxes. Income tax expense for the six months ended June 30, 2016 and 2015 was recorded at 34.2% and 34.9% of pre-tax net income, respectively. The effective tax rates for both periods were 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 our pre-tax loss. The permanent differences were primarily for compensation amounts expensed for book purposes versus the amounts deductible for income tax purposes related to stock-based compensation vesting during the six months ended June 30, 2016 and 2015 at stock prices lower than the grant date values. In addition, during the six months ended June 30, 2016, we recorded a valuation allowance of $0.9 million and $0.6 million for Montana net operating losses and federal charitable contribution carryovers, respectively, based on management’s assessment that it is more likely than not that these net deferred tax assets will not be realized prior to their expiration due to their short carryover periods, current economic conditions and expectations for the future.
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. 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, 2016 and 2015 are presented below:
 
Six Months Ended June 30,
 
2016
 
2015
 
(In thousands)
Net cash provided by operating activities
$
91,401

 
$
229,886

Net cash used in investing activities
(115,413
)
 
(374,500
)
Net cash provided by financing activities
20,757

 
112,487

Decrease in cash and cash equivalents
$
(3,255
)
 
$
(32,127
)

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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 prices on a portion of our production, thereby mitigating our exposure to oil price declines, but these transactions may also limit our cash flow in periods of rising oil prices. Prices for oil have declined significantly since mid-2014, which has substantially decreased our cash flows provided by operating activities. The decline in operating cash flows caused by lower oil prices is partially offset by cash flows from our derivative contracts. On February 2, 2016, we completed a public equity offering resulting in net proceeds of $183.0 million, after deducting underwriting discounts and commissions and offering expenses, which we used for general corporate purposes. Our existing revolving credit facility provides additional liquidity, with a current borrowing base and elected commitment amount of $1,150.0 million. The next redetermination of the borrowing base is scheduled for October 1, 2016. We believe we have adequate liquidity to fund planned 2016 capital expenditures and to meet our near-term future obligations. For additional information on the impact of changing prices on our financial position, see Item 3. “Quantitative and Qualitative Disclosures about Market Risk” below.
Cash flows provided by operating activities
Net cash provided by operating activities was $91.4 million and $229.9 million for the six months ended June 30, 2016 and 2015, respectively. The change in cash flows from operating activities for the period ended June 30, 2016 as compared to 2015 was primarily the result of lower 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 $139.8 million at June 30, 2016 due to decreases in our current assets, primarily due to the impact of increases in the forward commodity price curve on our short-term derivative instruments. As of June 30, 2016, we had $1,107.3 million of liquidity available, including $6.5 million in cash and cash equivalents and $1,100.8 million of unused borrowing base committed capacity available under our revolving credit facility. At June 30, 2015, we had a working capital deficit of $167.6 million.
Cash flows used in investing activities
Net cash used in investing activities was $115.4 million and $374.5 million during the six months ended June 30, 2016 and 2015, respectively. 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. Net cash used in investing activities during the six months ended June 30, 2015 was primarily attributable to $586.7 million in capital expenditures primarily for drilling and development costs, partially offset by $213.3 million of derivative settlements received as a result of lower crude oil pricing.
Our capital expenditures are summarized in the following table:
 
Six Months Ended June 30, 2016
 
(In thousands)
Capital expenditures:
 
E&P
$
120,859

OMS
87,882

OWS
650

Other capital expenditures(1)
9,852

Total capital expenditures(2)
$
219,243

 ___________________
(1)
Other capital expenditures include such items as administrative capital and capitalized interest.
(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 2016 capital expenditure budget is $400 million, which includes $340 million for E&P capital expenditures and $60 million for non-E&P capital expenditures, including OWS, administrative capital and capitalized interest. Our planned E&P capital expenditures include $200 million of drilling and completion capital expenditures for operated and non-operated wells (including expected savings from services provided by OWS and OMS) and $140 million of OMS capital expenditures (including Wild Basin infrastructure).

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While we have budgeted $400 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. Additionally, if we acquire additional acreage, our capital expenditures may be higher than budgeted. We believe that cash on hand, cash flows from operating activities, proceeds from cash settlements under our derivative contracts and availability under our revolving credit facility should be sufficient to fund our 2016 capital expenditure budget. However, because the operated wells funded by our 2016 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 be adjusted as business conditions warrant. The amount, timing and allocation of capital expenditures is largely discretionary and within our control. If oil prices remain low for an extended period of time or continue to decline, 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 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 $20.8 million and $112.5 million for the six months ended June 30, 2016 and 2015, respectively. For the six months ended June 30, 2016, cash provided by financing activities 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. Net cash provided by financing activities during the six months ended June 30, 2015 was primarily due to net proceeds from the issuance of our common stock and proceeds from borrowings under our revolving credit facility, partially offset by principal payments on our revolving credit facility. For both the six months ended June 30, 2016 and 2015, cash was used in financing activities for the purchases of treasury stock for shares that employees surrendered back to us to pay tax withholdings upon the vesting of restricted stock awards.
Sale of common stock. On February 2, 2016, we completed a public offering of 39,100,000 shares of our common stock at an offering price of $4.685 per share. We used the net proceeds from the offering of $183.0 million, after deducting underwriting discounts and commissions and offering expenses, for general corporate purposes.
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, 2016. 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 our 7.25% senior unsecured notes due February 1, 2019 (the “2019 Notes”) are retired or refinanced 90 days prior to their maturity date. On February 23, 2016, the lenders under the Credit Facility (the “Lenders”) completed their regular semi-annual redetermination of the borrowing base scheduled for April 1, 2016, resulting in a decrease in the borrowing base and aggregate elected commitment from $1,525.0 million to $1,150.0 million. The next redetermination of the borrowing base is scheduled for October 1, 2016.
At June 30, 2016, we had $35.0 million of borrowings at a weighted average interest rate of 2.0% and $14.2 million of outstanding letters of credit issued under the Credit Facility. At June 30, 2016, we had an unused borrowing base committed capacity of $1,100.8 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;

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•
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, 2016. At June 30, 2016, our consolidated EBITDAX was $631.0 million and our consolidated Interest Expense was $157.1 million, resulting in a ratio of 4.0 as compared to a minimum required ratio of 2.5. In addition, as of June 30, 2016, our consolidated current assets and consolidated current liabilities (as described above) were $1,316.7 million and $345.2 million, respectively, resulting in a Current Ratio of 3.8 as compared to a minimum required ratio of 1.0. Given the extended decline 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. As of June 30, 2016, our long-term debt includes outstanding senior unsecured note obligations of $2,123.4 million, including $399.0 million of the 2019 Notes, $397.7 million of 6.5% senior unsecured notes due November 1, 2021 (the “2021 Notes”), $940.5 million of 6.875% senior unsecured notes due March 15, 2022 (the “2022 Notes”) and $386.2 million of 6.875% senior unsecured notes due January 15, 2023 (the “2023 Notes,” and together with the 2019 Notes, the 2021 Notes and the 2022 Notes, the “Notes”). Interest on the Notes is payable semi-annually in arrears.
Prior to certain dates, we have certain options to redeem up to 35% of the Notes at a certain redemption price based on a percentage of the principal amount, plus accrued and unpaid interest to the redemption date, with the proceeds of certain equity offerings so long as the redemption occurs within 180 days of completing such equity offering and at least 65% of the aggregate principal amount of the Notes remains outstanding after such redemption. Prior to certain dates, we have the option to redeem some or all of the 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. We may from time to time seek to retire or purchase our outstanding 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 Notes are guaranteed on a senior unsecured basis by our material subsidiaries. The indentures governing the 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 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.
In March and April 2016, we repurchased an aggregate principal amount of $76.6 million of our outstanding Notes, consisting of $1.0 million principal amount of our 2019 Notes, $2.3 million principal amount of our 2021 Notes, $59.5 million principal amount of our 2022 Notes and $13.8 million principal amount of our 2023 Notes, for an aggregate cost of $56.9 million, including accrued interest and fees. As a result of these repurchases, we recognized pre-tax gains of $11.6 million and $18.7 million, which were net of unamortized deferred financing costs write-offs of $0.5 million and $1.0 million, respectively, and are reflected in gain on extinguishment of debt in the Company’s Condensed Consolidated Statement of Operations for the three and six months ended June 30, 2016, respectively.
Obligations and commitments
We have the following contractual obligations and commitments as of June 30, 2016:
 

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Payments due by period
Contractual obligations
Total
 
Within 1
year
 
1-3 years
 
3-5 years
 
More than
5 years
 
(In thousands)
Senior unsecured notes(1)
$
2,123,397

 
$
—

 
$
399,000

 
$
—

 
$
1,724,397

Interest payments on senior unsecured notes(1)
802,774

 
145,988

 
291,977

 
234,122

 
130,687

Borrowings under revolving credit facility(1)
35,000

 
—

 
—

 
35,000

 
—

Interest payments on borrowings under revolving credit facility(1)
44

 
44

 
—

 
—

 
—

Asset retirement obligations(2)
37,128

 
738

 
1,493

 
635

 
34,262

Operating leases(3)
22,598

 
6,499

 
9,863

 
6,236

 
—

Volume commitment agreements(3)
441,999

 
19,563

 
99,433

 
108,632

 
214,371

Purchase agreements(3)
38,821

 
4,847

 
16,874

 
16,700

 
400

Total contractual cash obligations
$
3,501,761

 
$
177,679

 
$
818,640

 
$
401,325

 
$
2,104,117

__________________  
(1)
See Note 8 to our unaudited condensed consolidated financial statements for a description of our senior unsecured notes, revolving credit facility and related interest payments. As of June 30, 2016, we had $35.0 million of borrowings and $14.2 million of outstanding letters of credit issued under our revolving credit facility.
(2)
Amounts represent our estimate of future asset retirement obligations. Because these costs typically extend many years into the future, estimating these future costs requires management to make estimates and judgments that are subject to future revisions based upon numerous factors, including the rate of inflation, changing technology and the political and regulatory environment. See Note 9 to our unaudited condensed consolidated financial statements.
(3)
See Note 15 to our unaudited condensed consolidated financial statements for a description of our operating leases, volume commitment agreements and purchase agreements.

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.

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Cash Interest
We define Cash Interest as interest expense plus capitalized interest less amortization and write-offs of deferred financing costs included in interest expense. Cash Interest is not a measure of interest expense as determined by United States generally accepted accounting principles, or 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.
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,
 
2016
 
2015
 
2016
 
2015
 
(In thousands)
Interest expense
$
34,979

 
$
37,405

 
$
73,718

 
$
76,189

Capitalized interest
4,835

 
4,851

 
9,303

 
8,776

Amortization of deferred financing costs(1)
(2,030
)
 
(2,368
)
 
(5,947
)
 
(3,956
)
Cash Interest
$
37,784

 
$
39,888

 
$
77,074

 
$
81,009

___________________
(1)
Amortization of deferred financing costs included write-offs of unamortized deferred financing costs of $1.8 million for the six months ended June 30, 2016 and $0.5 million for the three and six months ended June 30, 2015. In each period, the unamortized deferred financing costs were written off in proportion to the decreases in our Credit Facility borrowing base.

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 non-recurring 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.
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 and our ability to generate cash from our business operations after interest and capital spending.

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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,
 
2016
 
2015
 
2016
 
2015
 
(In thousands)
Net loss
$
(89,931
)
 
$
(53,230
)
 
$
(154,386
)
 
$
(71,271
)
Loss on sale of properties
1,311

 
—

 
1,311

 
—

Gain on extinguishment of debt
(11,642
)
 
—

 
(18,658
)
 
—

Net (gain) loss on derivative instruments
90,846

 
39,424

 
76,471

 
(7,648
)
Derivative settlements(1)
30,477

 
104,077

 
103,790

 
213,336

Interest expense, net of capitalized interest
34,979

 
37,405

 
73,718

 
76,189

Depreciation, depletion and amortization
122,488

 
119,218

 
244,937

 
237,696

Impairment
23

 
19,516

 
3,585

 
24,837

Rig termination
—

 
2,815

 
—

 
3,895

Exploration expenses
340

 
1,082

 
703

 
1,925

Stock-based compensation expenses
6,249

 
6,057

 
12,979

 
13,663

Income tax benefit
(52,498
)
 
(30,845
)
 
(80,127
)
 
(38,221
)
Other non-cash adjustments
(484
)
 
(97
)
 
723

 
(101
)
Adjusted EBITDA
132,158

 
245,422

 
265,046

 
454,300

Cash Interest
(37,784
)
 
(39,888
)
 
(77,074
)
 
(81,009
)
Capital expenditures(2)
(131,288
)
 
(170,408
)
 
(219,243
)
 
(441,513
)
Capitalized interest
4,835

 
4,851

 
9,303

 
8,776

Free Cash Flow
$
(32,079
)
 
$
39,977

 
$
(21,968
)
 
$
(59,446
)
 
 
 
 
 
 
 
 
Net cash provided by operating activities
$
137,452

 
$
141,525

 
$
91,401

 
$
229,886

Derivative settlements(1)
30,477

 
104,077

 
103,790

 
213,336

Interest expense, net of capitalized interest
34,979

 
37,405

 
73,718

 
76,189

Rig termination
—

 
2,815

 
—

 
3,895

Exploration expenses
340

 
1,082

 
703

 
1,925

Deferred financing costs amortization and other
(1,486
)
 
(3,404
)
 
(6,552
)
 
(5,059
)
Changes in working capital
(69,120
)
 
(37,981
)
 
1,263

 
(65,771
)
Other non-cash adjustments
(484
)
 
(97
)
 
723

 
(101
)
Adjusted EBITDA
132,158

 
245,422

 
265,046

 
454,300

Cash Interest
(37,784
)
 
(39,888
)
 
(77,074
)
 
(81,009
)
Capital expenditures(2)
(131,288
)
 
(170,408
)
 
(219,243
)
 
(441,513
)
Capitalized interest
4,835

 
4,851

 
9,303

 
8,776

Free Cash Flow
$
(32,079
)
 
$
39,977

 
$
(21,968
)
 
$
(59,446
)
___________________
(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.


42
Table of Contents

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,
 
2016
 
2015
 
2016
 
2015
 
(In thousands)
Loss before income taxes
$
(158,978
)
 
$
(99,164
)
 
$
(264,744
)
 
$
(133,172
)
Loss on sale of properties
1,669

 
—

 
1,669

 
—

Gain on extinguishment of debt
(11,642
)
 
—

 
(18,658
)
 
—

Net (gain) loss on derivative instruments
90,846

 
39,424

 
76,471

 
(7,648
)
Derivative settlements(1)
30,477

 
104,077

 
103,790

 
213,336

Interest expense, net of capitalized interest
34,979

 
37,405

 
73,718

 
76,189

Depreciation, depletion and amortization
120,039

 
118,049

 
240,881

 
235,589

Impairment
23

 
19,516

 
1,154

 
24,837

Rig termination
—

 
2,815

 
—

 
3,895

Exploration expenses
340

 
1,082

 
703

 
1,925

Stock-based compensation expenses
6,077

 
5,973

 
12,625

 
13,515

Other non-cash adjustments
(484
)
 
(97
)
 
723

 
(101
)
Adjusted EBITDA
$
113,346

 
$
229,080

 
$
228,332

 
$
428,365

___________________
(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.

Well Services
 
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
 
2016
 
2015
 
2016
 
2015
 
 
(In thousands)
Income (loss) before income taxes
 
$
(2,142
)
 
$
9,030

 
$
1,885

 
$
18,638

Depreciation, depletion and amortization
 
3,895

 
5,008

 
8,127

 
9,526

Stock-based compensation expenses
 
235

 
443

 
899

 
986

Adjusted EBITDA
 
$
1,988

 
$
14,481

 
$
10,911

 
$
29,150


Midstream Services
 
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
 
2016
 
2015
 
2016
 
2015
 
 
(In thousands)
Income before income taxes
 
$
18,040

 
$
15,922

 
$
33,198

 
$
25,211

Gain on sale of properties
 
(358
)
 
—

 
(358
)
 
—

Depreciation, depletion and amortization
 
1,732

 
1,375

 
3,415

 
2,561

Impairment
 
—

 
—

 
2,431

 
—

Stock-based compensation expenses
 
224

 
119

 
443

 
323

Adjusted EBITDA
 
$
19,638

 
$
17,416

 
$
39,129

 
$
28,095



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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 and non-recurring items, including non-cash changes in the fair value of derivative instruments, impairment and other similar non-cash and non-recurring charges, 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.
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,
 
2016
 
2015
 
2016
 
2015
 
(In thousands, except per share data)
Net loss
$
(89,931
)
 
$
(53,230
)
 
$
(154,386
)
 
$
(71,271
)
Loss on sale of properties
1,311

 
—

 
1,311

 
—

Gain on extinguishment of debt
(11,642
)
 
—

 
(18,658
)
 
—

Net (gain) loss on derivative instruments
90,846

 
39,424

 
76,471

 
(7,648
)
Derivative settlements(1)
30,477

 
104,077

 
103,790

 
213,336

Impairment
23

 
19,516

 
3,585

 
24,837

Rig termination
—

 
2,815

 
—

 
3,895

Amortization of deferred financing costs(2)
2,030

 
2,368

 
5,947

 
3,956

Other non-cash adjustments
(484
)
 
(97
)
 
723

 
(101
)
Tax impact(3)
(42,075
)
 
(62,871
)
 
(64,731
)
 
(89,115
)
Adjusted Net Income (Loss)
$
(19,445
)
 
$
52,002

 
$
(45,948
)
 
$
77,889

 
 
 
 
 
 
 
 
Diluted loss per share
$
(0.51
)
 
$
(0.39
)
 
$
(0.91
)
 
$
(0.58
)
Loss on sale of properties
0.01

 
—

 
0.01

 
—

Gain on extinguishment of debt
(0.07
)
 
—

 
(0.11
)
 
—

Net (gain) loss on derivative instruments
0.51

 
0.29

 
0.45

 
(0.06
)
Derivative settlements(1)
0.17

 
0.76

 
0.61

 
1.73

Impairment
—

 
0.14

 
0.02

 
0.20

Rig termination
—

 
0.02

 
—

 
0.03

Amortization of deferred financing costs(2)
0.01

 
0.02

 
0.03

 
0.03

Other non-cash adjustments
—

 
—

 
—

 
—

Tax impact(3)
(0.23
)
 
(0.46
)
 
(0.37
)
 
(0.72
)
Adjusted Diluted Earnings (Loss) Per Share
$
(0.11
)
 
$
0.38

 
$
(0.27
)
 
$
0.63

 
 
 
 
 
 
 
 
Diluted weighted average shares outstanding
176,984

 
136,859

 
169,953

 
123,157

 
 
 
 
 
 
 
 
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)
As of June 30, 2016, Adjusted Net Income (Loss) includes the non-cash adjustment for amortization of deferred financing costs. Comparative periods have been conformed. The amortization of deferred financing costs is included in interest expense on our Condensed Consolidated Statement of Operations. Amortization of deferred financing costs included write-offs of unamortized deferred financing costs of $1.8 million for the six months ended June 30, 2016 and $0.5 million for the three and six months ended June 30, 2015. In each period, the unamortized deferred financing costs were written off in proportion to the decreases in our Credit Facility borrowing base.
(3)
The tax impact is computed utilizing our effective tax rate applicable to the adjustments for certain non-cash and non-recurring items.

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Table of Contents


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.
Critical Accounting Policies and Estimates
There have been no material changes in our critical accounting policies and estimates from those disclosed in our 2015 Annual Report.
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. We are currently evaluating the effect that adopting this guidance will have on our financial position, cash flows and results of operations.
Going concern. In August 2014, the FASB issued Accounting Standards Update No. 2014-15, Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern (“ASU 2014-15”). ASU 2014-15 codifies in GAAP management’s responsibility to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern and to provide related footnote disclosures. ASU 2014-15 is effective for the annual reporting period ending after December 15, 2016 and for annual periods and interim periods thereafter. The adoption of this guidance will not impact our financial position, cash flows or results of operations but could result in additional disclosures.
Inventory. In July 2015, the FASB issued Accounting Standards Update No. 2015-11, Simplifying the Measurement of Inventory (“ASU 2015-11”). ASU 2015-11 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 (FIFO) or average cost methods. ASU 2015-11 is effective for fiscal years beginning after December 15, 2016, including interim periods within those years. We are currently evaluating the effect that adopting this guidance will have on our 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. We are currently evaluating the effect that adopting this guidance will have on our 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. We are currently evaluating the effect that adopting this guidance will have on our financial position, cash flows and results of operations.
Embedded derivatives. In March 2016, the FASB issued Accounting Standards Update No. 2016-06, Contingent Put and Call Options in Debt Instruments (“ASU 2016-06”), which clarifies what steps are required when assessing whether the economic characteristics and risks of call (put) options are clearly and closely related to the economic characteristics and risks of their debt hosts, which is one of the criteria for bifurcating an embedded derivative. ASU 2016-06 is effective for fiscal years beginning after December 15, 2016, including interim periods within those years. We do not expect the adoption of this guidance to have a material impact on our financial position, cash flows or results of operations.
Stock-based compensation. In March 2016, the FASB issued 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

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Table of Contents

flows. ASU 2016-09 is effective for fiscal years beginning after December 15, 2016, including interim periods within those years. We are currently evaluating the effect that adopting this guidance will have on our financial position, cash flows and results of operations.
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 15 to our unaudited condensed consolidated financial statements for a description of our commitments and contingencies.

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Table of Contents

Item 3. — Quantitative and Qualitative Disclosures About Market Risk
The following market risk disclosures should be read in conjunction with the quantitative and qualitative disclosures about market risk contained in our 2015 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 prices. As of June 30, 2016, we utilized two-way and three-way costless collar options and swaps to reduce the volatility of oil prices on a significant portion of our future expected oil production. 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 WTI crude oil 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. A swap is a sold call and a purchased put established at the same price (both ceiling and floor).
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.
The following is a summary of our derivative contracts as of June 30, 2016:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Settlement
Period
 
Derivative
Instrument
 
Total
Notional
Amount of Oil
 
Weighted Average Prices
 
Fair Value
Asset (Liability)
 
 
 
Swap
 
Sub-Floor
 
Floor
 
Ceiling
 
 
 
 
 
(Barrels)
 
($/Barrel)
 
(In thousands)
2016
 
Swaps
 
5,886,000

 
$
49.64

 
 
 


 


 
$
1,157

2017
 
Swaps
 
4,694,000

 
$
47.79

 
 
 
 
 
 
 
(18,429
)
2017
 
Two-way collars
 
668,000

 
 
 
 
 
$
40.00

 
$
47.58

 
(4,427
)
2017
 
Three-way collars
 
1,336,000

 

 
$
30.00

 
$
45.00

 
$
59.39

 
(923
)
2018
 
Swaps
 
310,000

 
$
47.68

 
 
 
 
 
 
 
(1,519
)
2018
 
Two-way collars
 
62,000

 
 
 
 
 
$
40.00

 
$
47.58

 
(453
)
2018
 
Three-way collars
 
124,000

 
 
 
$
30.00

 
$
45.00

 
$
59.39

 
(194
)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
$
(24,788
)
A 10% increase in crude oil prices would decrease the fair value of our derivative position by approximately $58.9 million, while a 10% decrease in crude oil prices would increase the fair value by approximately $58.0 million.
Interest rate risk. We had (i) $399.0 million of senior unsecured notes at a fixed cash interest rate of 7.25% per annum, (ii) $397.7 million of senior unsecured notes at a fixed cash interest rate of 6.5% per annum and (iii) $1,326.7 million of senior unsecured notes at a fixed cash interest rate of 6.875% per annum outstanding at June 30, 2016. At June 30, 2016, we had $35.0 million of borrowings and $14.2 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, 2016, 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. We are also subject to credit risk due to concentration of our

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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.
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 the net amounts due to and from the counterparties under the derivative contracts. We had a net derivative liability position of $24.8 million at June 30, 2016.
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.
We may, from time to time, 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. Our investment policy requires that our counterparties have minimum credit ratings thresholds and provides maximum counterparty exposure values. Although we do not anticipate any of our commercial paper issuers being unable to pay us upon maturity, we take a risk in purchasing the commercial paper instruments available in the marketplace. If a commercial paper issuer is unable to return investment proceeds to us at the maturity date, it could take a significant amount of time to recover all or a portion of the assets originally invested. Our commercial paper balance was $36,000 at June 30, 2016.
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, 2016. 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, 2016.
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, 2016 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II — OTHER INFORMATION
Item 1. — Legal Proceedings
See Part I, Item 1, Note 15 to our unaudited condensed consolidated financial statements entitled “Commitments and Contingencies,” which is incorporated in this item by reference.
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 2015 Annual Report. There have been no material changes in our risk factors from those described in our 2015 Annual Report.
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, 2016:
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, 2016
 
23,293

 
$
7.08

 
—

 
—

May 1 - May 31, 2016
 
32,354

 
9.69

 
—

 
—

June 1 - June 30, 2016
 
30,728

 
9.36

 
—

 
—

Total
 
86,375

 
8.87

 
—

 
—

___________________ 
(1)
Represent 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.

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Item 6. — Exhibits
Exhibit
No.
 
Description of Exhibit
 
 
 
3.1(a)*
 
Conformed version of Amended and Restated Certificate of Incorporation of Oasis Petroleum Inc., as amended by amendment filed on June 30, 2016.
 
 
 
10.1
 
Second Amendment to the Amended and Restated 2010 Long Term Incentive Plan of Oasis Petroleum Inc. (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on May 10, 2016 and incorporated herein by reference).
 
 
 
10.2(a)
 
Sixth Amendment to Second Amended and Restated Credit Agreement dated as of August 8, 2016 among Oasis Petroleum Inc., as Parent, Oasis Petroleum North America LLC, as Borrower, the Other Credit Parties party thereto, Wells Fargo Bank, N.A., as Administrative Agent and the Lenders party thereto.
 
 
31.1(a)
 
Sarbanes-Oxley Section 302 certification of Principal Executive Officer.
 
 
31.2(a)
 
Sarbanes-Oxley Section 302 certification of Principal Financial Officer.
 
 
32.1(b)
 
Sarbanes-Oxley Section 906 certification of Principal Executive Officer.
 
 
32.2(b)
 
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.

* This exhibit is being filed pursuant to Item 601(b)(3)(i) of Regulation S-K which requires a conformed version of our charter reflecting all amendments in one document. The exhibit reflects our Amended and Restated Certificate of Incorporation as filed with the Delaware Secretary of State on June 22, 2010, revised for the amendment filed on June 30, 2016, which changed the first sentence of Article Four by increasing the total number of authorized shares from 350,000,000 to 500,000,000 and the total authorized common shares from 300,000,000 to 450,000,000, as approved by shareholders on May 4, 2016.


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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
OASIS PETROLEUM INC.
 
 
 
 
 
Date:
August 9, 2016
 
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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EXHIBIT INDEX
 
Exhibit
No.
 
Description of Exhibit
 
 
 
3.1(a)*
 
Conformed version of Amended and Restated Certificate of Incorporation of Oasis Petroleum Inc., as amended by amendment filed on June 30, 2016.
 
 
 
10.1
 
Second Amendment to the Amended and Restated 2010 Long Term Incentive Plan of Oasis Petroleum Inc. (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on May 10, 2016 and incorporated herein by reference).
 
 
 
10.2(a)
 
Sixth Amendment to Second Amended and Restated Credit Agreement dated as of August 8, 2016 among Oasis Petroleum Inc., as Parent, Oasis Petroleum North America LLC, as Borrower, the Other Credit Parties party thereto, Wells Fargo Bank, N.A., as Administrative Agent and the Lenders party thereto.
 
 
31.1(a)
 
Sarbanes-Oxley Section 302 certification of Principal Executive Officer.
 
 
31.2(a)
 
Sarbanes-Oxley Section 302 certification of Principal Financial Officer.
 
 
32.1(b)
 
Sarbanes-Oxley Section 906 certification of Principal Executive Officer.
 
 
32.2(b)
 
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.

* This exhibit is being filed pursuant to Item 601(b)(3)(i) of Regulation S-K which requires a conformed version of our charter reflecting all amendments in one document. The exhibit reflects our Amended and Restated Certificate of Incorporation as filed with the Delaware Secretary of State on June 22, 2010, revised for the amendment filed on June 30, 2016, which changed the first sentence of Article Four by increasing the total number of authorized shares from 350,000,000 to 500,000,000 and the total authorized common shares from 300,000,000 to 450,000,000, as approved by shareholders on May 4, 2016.


52