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EX-32.2 - EXHIBIT 32.2 - Oasis Petroleum Inc.oas-ex322x9302018xq33q18ma.htm
EX-32.1 - EXHIBIT 32.1 - Oasis Petroleum Inc.oas-ex321x9302018xq33q18ma.htm
EX-31.2 - EXHIBIT 31.2 - Oasis Petroleum Inc.oas-ex312x9302018xq33q18ma.htm
EX-31.1 - EXHIBIT 31.1 - Oasis Petroleum Inc.oas-ex311x9302018xq33q18ma.htm

 
 
 
 
 
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 September 30, 2018
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 every Interactive Data File required to be submitted 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 such files).    Yes ý  No ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act. 
Large accelerated filer
ý
Accelerated filer
¨
 
 
 
 
Non-accelerated filer
o  
Smaller reporting company
¨
 
 
 
 
 
 
Emerging growth company
¨
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.  ¨ 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes ¨ No ý
Number of shares of the registrant’s common stock outstanding at November 1, 2018: 318,434,087 shares.
 
 
 
 
 




OASIS PETROLEUM INC.
FORM 10-Q
FOR THE QUARTER ENDED SEPTEMBER 30, 2018
TABLE OF CONTENTS
 
Page



PART I — FINANCIAL INFORMATION
Item 1. — Financial Statements (Unaudited)
Oasis Petroleum Inc.
Condensed Consolidated Balance Sheets
(Unaudited)
 
September 30, 2018
 
December 31, 2017
 
(In thousands, except share data)
ASSETS
 
 
 
Current assets
 
 
 
Cash and cash equivalents
$
16,892

 
$
16,720

Accounts receivable, net
428,184

 
363,580

Inventory
31,409

 
19,367

Prepaid expenses
6,444

 
7,631

Derivative instruments

 
344

Intangible assets, net
375

 

Other current assets
192

 
193

Total current assets
483,496

 
407,835

Property, plant and equipment
 
 
 
Oil and gas properties (successful efforts method)
8,671,144

 
7,838,955

Other property and equipment
1,088,781

 
868,746

Less: accumulated depreciation, depletion, amortization and impairment
(2,859,788
)
 
(2,534,215
)
Total property, plant and equipment, net
6,900,137

 
6,173,486

Derivative instruments

 
9

Long-term inventory
12,610

 
12,200

Other assets
20,188

 
21,600

Total assets
$
7,416,431

 
$
6,615,130

LIABILITIES AND STOCKHOLDERS’ EQUITY
 
 
 
Current liabilities
 
 
 
Accounts payable
$
17,206

 
$
13,370

Revenues and production taxes payable
287,333

 
213,995

Accrued liabilities
307,526

 
236,480

Accrued interest payable
20,574

 
38,963

Derivative instruments
180,129

 
115,716

Advances from joint interest partners
3,878

 
4,916

Other current liabilities
40

 
40

Total current liabilities
816,686

 
623,480

Long-term debt
2,633,009

 
2,097,606

Deferred income taxes
230,504

 
305,921

Asset retirement obligations
51,357

 
48,511

Derivative instruments
33,017

 
19,851

Other liabilities
7,775

 
6,182

Total liabilities
3,772,348

 
3,101,551

Commitments and contingencies (Note 17)

 

Stockholders’ equity
 
 
 
Common stock, $0.01 par value: 900,000,000 and 450,000,000 shares authorized at September 30, 2018 and December 31, 2017, respectively; 320,507,783 shares issued and 318,419,144 shares outstanding at September 30, 2018 and 270,627,014 shares issued and 269,295,466 shares outstanding at December 31, 2017
3,157

 
2,668

Treasury stock, at cost: 2,088,639 and 1,331,548 shares at September 30, 2018 and December 31, 2017, respectively
(28,985
)
 
(22,179
)
Additional paid-in capital
3,070,642

 
2,677,217

Retained earnings
460,712

 
717,985

Oasis share of stockholders’ equity
3,505,526

 
3,375,691

Non-controlling interests
138,557

 
137,888

Total stockholders’ equity
3,644,083

 
3,513,579

Total liabilities and stockholders’ equity
$
7,416,431

 
$
6,615,130


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

1


Oasis Petroleum Inc.
Condensed Consolidated Statements of Operations
(Unaudited)
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2018
 
2017
 
2018
 
2017
 
(In thousands, except per share data)
Revenues
 
 
 
 
 
 
 
Oil and gas revenues
$
452,643

 
$
248,648

 
$
1,212,235

 
$
704,533

Purchased oil and gas sales
46,356

 
21,195

 
121,971

 
56,917

Midstream revenues
31,187

 
18,767

 
88,451

 
48,939

Well services revenues
16,262

 
16,138

 
46,344

 
33,566

Total revenues
546,448

 
304,748

 
1,469,001

 
843,955

Operating expenses
 
 
 
 
 
 
 
Lease operating expenses
48,534

 
45,334

 
137,456

 
133,871

Midstream operating expenses
8,652

 
4,301

 
24,325

 
10,891

Well services operating expenses
11,405

 
10,288

 
32,352

 
23,858

Marketing, transportation and gathering expenses
30,713

 
15,028

 
74,559

 
38,018

Purchased oil and gas expenses
46,088

 
21,701

 
121,251

 
57,683

Production taxes
38,722

 
21,052

 
103,748

 
60,322

Depreciation, depletion and amortization
162,984

 
132,289

 
465,819

 
384,246

Exploration expenses
22,315

 
854

 
23,701

 
4,010

Impairment

 
139

 
384,228

 
6,021

General and administrative expenses
34,859

 
21,368

 
91,029

 
67,170

Total operating expenses
404,272

 
272,354

 
1,458,468

 
786,090

Gain on sale of properties
36,869

 

 
38,823

 

Operating income
179,045

 
32,394

 
49,356

 
57,865

Other income (expense)
 
 
 
 
 
 
 
Net gain (loss) on derivative instruments
(48,544
)
 
(54,310
)
 
(239,945
)
 
52,297

Interest expense, net of capitalized interest
(39,560
)
 
(37,389
)
 
(117,616
)
 
(110,548
)
Loss on extinguishment of debt
(47
)
 

 
(13,698
)
 

Other income (expense)
111

 
(605
)
 
146

 
(755
)
Total other expense
(88,040
)
 
(92,304
)
 
(371,113
)
 
(59,006
)
Income (loss) before income taxes
91,005

 
(59,910
)
 
(321,757
)
 
(1,141
)
Income tax benefit (expense)
(24,782
)
 
18,846

 
75,391

 
470

Net income (loss) including non-controlling interests
66,223

 
(41,064
)
 
(246,366
)
 
(671
)
Less: Net income attributable to non-controlling interests
3,882

 
150

 
10,907

 
150

Net income (loss) attributable to Oasis
$
62,341

 
$
(41,214
)
 
$
(257,273
)
 
$
(821
)
Earnings (loss) attributable to Oasis per share:
 
 
 
 
 
 
 
Basic (Note 15)
$
0.20

 
$
(0.18
)
 
$
(0.84
)
 
$
0.00

Diluted (Note 15)
0.20

 
(0.18
)
 
(0.84
)
 
0.00

Weighted average shares outstanding:
 
 
 
 
 
 
 
Basic (Note 15)
313,167

 
233,389

 
305,533

 
233,248

Diluted (Note 15)
316,387

 
233,389

 
305,533

 
233,248


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


2


Oasis Petroleum Inc.
Condensed Consolidated Statement of Changes in Stockholders’ Equity
(Unaudited)
 
Attributable to Oasis
 
 
 
 
 
Common Stock
 
Treasury Stock
 
Additional
Paid-in Capital
 
Retained Earnings
 
Non-controlling Interests
 
Total
Stockholders’
Equity
Shares
 
Amount
 
Shares
 
Amount
 
 
(In thousands)
Balance at December 31, 2017
269,295

 
$
2,668

 
1,332

 
$
(22,179
)
 
$
2,677,217

 
$
717,985

 
$
137,888

 
$
3,513,579

Permian Basin Acquisition issuance
46,000

 
460

 

 

 
370,760

 

 

 
371,220

Other (2017 issuance of common stock and Oasis Midstream common units)

 

 

 

 
38

 

 
(125
)
 
(87
)
Equity-based compensation
3,881

 
29

 

 

 
22,627

 

 
280

 
22,936

Distributions to non-controlling interest owners

 

 

 

 

 

 
(10,393
)
 
(10,393
)
Treasury stock - tax withholdings
(757
)
 

 
757

 
(6,806
)
 

 

 

 
(6,806
)
Net income (loss)

 

 

 

 

 
(257,273
)
 
10,907

 
(246,366
)
Balance at September 30, 2018
318,419

 
$
3,157

 
2,089

 
$
(28,985
)
 
$
3,070,642

 
$
460,712

 
$
138,557

 
$
3,644,083


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


3


Oasis Petroleum Inc.
Condensed Consolidated Statements of Cash Flows
(Unaudited)
 
Nine Months Ended September 30,
 
2018
 
2017
 
(In thousands)
Cash flows from operating activities:
 
 
 
Net loss including non-controlling interests
$
(246,366
)
 
$
(671
)
Adjustments to reconcile net loss including non-controlling interests to net cash provided by operating activities:
 
 
 
Depreciation, depletion and amortization
465,819

 
384,246

Loss on extinguishment of debt
13,698

 

Gain on sale of properties
(38,823
)
 

Impairment
384,228

 
6,021

Deferred income taxes
(75,418
)
 
(470
)
Derivative instruments
239,945

 
(52,297
)
Equity-based compensation expenses
21,586

 
20,451

Deferred financing costs amortization and other
20,074

 
12,666

Working capital and other changes:
 
 
 
Change in accounts receivable, net
(61,275
)
 
(81,022
)
Change in inventory
(12,076
)
 
(235
)
Change in prepaid expenses
1,196

 
823

Change in other current assets
1

 
276

Change in long-term inventory and other assets
(490
)
 
(12,843
)
Change in accounts payable, interest payable and accrued liabilities
50,308

 
32,282

Change in other current liabilities

 
(10,490
)
Change in other liabilities
(406
)
 

Net cash provided by operating activities
762,001

 
298,737

Cash flows from investing activities:
 
 
 
Capital expenditures
(841,088
)
 
(443,649
)
Acquisitions
(579,886
)
 

Proceeds from sale of properties
333,029

 
4,000

Costs related to sale of properties
(2,707
)
 

Derivative settlements
(162,013
)
 
(804
)
Advances from joint interest partners
(1,038
)
 
(2,502
)
Net cash used in investing activities
(1,253,703
)
 
(442,955
)
Cash flows from financing activities:
 
 
 
Proceeds from Revolving Credit Facilities
2,499,000

 
764,000

Principal payments on Revolving Credit Facilities
(1,959,000
)
 
(732,000
)
Repurchase of senior unsecured notes
(423,190
)
 

Proceeds from issuance of senior unsecured notes
400,000

 

Deferred financing costs
(7,650
)
 
(96
)
Proceeds from sale of Oasis Midstream common units, net of offering costs

 
115,813

Purchases of treasury stock
(6,806
)
 
(6,182
)
Distributions to non-controlling interests
(10,393
)
 

Other
(87
)
 
(55
)
Net cash provided by financing activities
491,874

 
141,480

Increase (decrease) in cash and cash equivalents
172

 
(2,738
)
Cash and cash equivalents:
 
 
 
Beginning of period
16,720

 
11,226

End of period
$
16,892

 
$
8,488

Supplemental non-cash transactions:
 
 
 
Change in accrued capital expenditures
$
79,011

 
$
63,499

Change in asset retirement obligations
2,854

 
3,112

Issuance of shares in connection with the Permian Basin Acquisition
371,220

 

Installment notes from acquisition

 
4,875

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

4


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 onshore, unconventional oil and natural gas resources in the United States. Oasis Petroleum North America LLC (“OPNA”) and Oasis Petroleum Permian LLC (“OP Permian”) conduct the Company’s exploration and production activities and own its proved and unproved oil and natural gas properties located in the North Dakota and Montana regions of the Williston Basin and the Texas region of the Delaware Basin, respectively. The Company also operates a midstream services business through OMS Holdings LLC (“OMS”) and a well services business through Oasis Well Services LLC (“OWS”), both of which are separate reportable business segments that are complementary to the Company’s primary development and production activities. The midstream services business is conducted by Oasis Midstream Partners LP (“OMP” or “Oasis Midstream”), which completed an initial public offering in September 2017. The Company owns the general partner and a majority of the outstanding units of OMP.
2. Summary of Significant Accounting Policies
Basis of Presentation
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, 2017 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 of the Company’s financial position, 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, 2017 (“2017 Annual Report”).
Consolidation. The accompanying condensed consolidated financial statements of the Company include the accounts of Oasis, the accounts of wholly-owned subsidiaries, and the accounts of OMP, which is considered a variable interest entity (“VIE”) for which the Company is the primary beneficiary. All significant intercompany balances and transactions have been eliminated upon consolidation.
Consolidated VIE. The Company has determined that the partners with equity at risk in OMP lack the authority, through voting rights or similar rights, to direct the activities that most significantly impact OMP’s economic performance. Therefore, as the limited partners of OMP do not have substantive kick-out or substantive participating rights over OMP GP LLC (“OMP GP”), the general partner to OMP, OMP is a VIE. Through the Company’s ownership interest in OMP GP, the Company has the authority to direct the activities that most significantly affect economic performance and the right to receive benefits that could be potentially significant to OMP. Therefore, the Company is considered the primary beneficiary and consolidates OMP and records a non-controlling interest for the interest owned by the public as of September 30, 2018.
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. A substantial or extended decline in 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.

5


Significant Accounting Policies
There have been no material changes to the Company’s critical accounting policies and estimates from those disclosed in the 2017 Annual Report, other than as noted below.
Revenue recognition. In the first quarter of 2018, the Company adopted 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 was applied on a modified retrospective basis. The adoption of ASU 2014-09 did not result in a material impact to the Company’s financial position, cash flows or results of operations. Enhanced disclosures in accordance with ASU 2014-09 have been provided in Note 3 – Revenue Recognition.
Financial instruments. In the first quarter of 2018, the Company adopted 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 was applied on a prospective basis and prior periods were not retrospectively adjusted. There was no material impact as a result of adoption as of September 30, 2018.
Statement of cash flows. In the first quarter of 2018, the Company adopted Accounting Standards Update No. 2016-15, Statement of Cash Flows (“ASU 2016-15”), which is intended to reduce diversity in practice in how certain transactions are classified in the statement of cash flows. ASU 2016-15 was applied on a prospective basis and prior periods were not retrospectively adjusted. There was no material impact as a result of adoption as of September 30, 2018.
Income taxes. In the first quarter of 2018, the Company adopted Accounting Standards Update No. 2016-16, Intra-Entity Transfers of Assets Other Than Inventory (“ASU 2016-16”), to improve the accounting for the income tax consequences of intra-entity transfers of assets other than inventory. ASU 2016-16 was applied on a prospective basis and prior periods were not retrospectively adjusted. There was no material impact as a result of adoption as of September 30, 2018.
In the third quarter of 2018, the Company finalized the accounting related to Accounting Standards Update No. 2018-05, Income Taxes (Topic 740) - Amendments to SEC Paragraphs Pursuant to SEC Staff Accounting Bulletin No. 118 (“ASU 2018-05”). This standard amends Accounting Standards Codification 740, Income Taxes (“ASC 740”) to provide guidance on accounting for the tax effects of the Tax Cuts and Jobs Act (the “Tax Act”) pursuant to Staff Accounting Bulletin No. 118, Income Tax Accounting Implications of the Tax Cuts and Jobs Act ("SAB 118"). See Note 13 – Income Taxes for the total impact as a result of adoption as of September 30, 2018.
Business combinations. In the first quarter of 2018, the Company adopted Accounting Standards Update No. 2017-01, Clarifying the Definition of a Business (“ASU 2017-01”), which provides guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. ASU 2017-01 requires entities to use a screen test to determine when an integrated set of assets and activities is not a business or if the integrated set of assets and activities needs to be further evaluated against the framework. ASU 2017-01 was applied on a prospective basis and prior periods were not retrospectively adjusted. There was no material impact as a result of adoption as of September 30, 2018.
Equity-based compensation. In the first quarter of 2018, the Company adopted Accounting Standards Update No. 2017-09, Scope of Modification Accounting (“ASU 2017-09”), which provides guidance about which changes to the terms or conditions of a share-based payment award require an entity to apply modification accounting. ASU 2017-09 was applied on a prospective basis and prior periods were not retrospectively adjusted. There was no material impact as a result of adoption as of September 30, 2018.
Recent Accounting Pronouncements
Leases. In February 2016, the Financial Accounting Standards Board (“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. This standard does not apply to leases to explore for or use minerals, oil or natural gas resources, including the right to explore for those natural resources. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, including interim periods within those years.
In January 2018, the FASB issued Accounting Standards Update No. 2018-01, Land Easement Practical Expedient for Transition to Topic 842, which provides an optional transition practical expedient to not evaluate under Topic 842 existing or expired land easements that were not previously accounted for as leases under Topic 840, Leases. The Company plans to elect this practical expedient.

6


In July 2018, the FASB issued Accounting Standards Update No. 2018-11, Targeted Improvements - Lease Topic 842, which allows entities another option for transition and also provides lessors with a practical expedient to combine lease and non-lease components. The Company will adopt the new leases standard using the required modified retrospective approach and plans to elect the option to recognize a cumulative effect adjustment of initially applying the guidance to the opening balance of retained earnings in the period of adoption, rather than recognizing in the earliest period presented. Prior period amounts will not be adjusted.
The Company is in the process of analyzing its lease arrangements and is continuing to identify and put in place necessary changes to its business processes and controls to support the adoption of the new standard, including implementing a new lease accounting software to assess the portfolio of leases, assist in the quantification of the expected impact on the consolidated financial statements and facilitate the calculations of the related accounting entries and disclosures. The Company is currently evaluating the effect that adopting the new lease guidance will have on its financial position, cash flows and results of operations.
Financial instruments. In August 2018, the FASB issued Accounting Standards Update No. 2018-13, Fair Value Measurement (Topic 820): Disclosure Framework—Changes to the Disclosure Requirements for Fair Value Measurement (“ASU 2018-13”), which improves the effectiveness of the disclosure requirements for fair value measurements. The changes affect all companies that are required to include fair value measurement disclosures. ASU 2018-13 is effective for fiscal years beginning after December 15, 2019, including interim periods within those years. An entity is permitted to early adopt the removed or modified disclosures upon the issuance of ASU 2018-13 and may delay adoption of the additional disclosures until their effective date. The Company does not expect the adoption of this guidance to have an impact on its financial position, cash flows or results of operations, but it may result in changes to disclosures.
3. Revenue Recognition
In May 2014, the FASB issued a new accounting standard related to revenue recognition, ASC 606 - Revenue from Contracts with Customers (“ASC 606”). This standard was effective in the first quarter of 2018 and the Company adopted the new standard using the modified retrospective method. The Company applied ASC 606 to all new contracts entered into after January 1, 2018 and all existing contracts for which all (or substantially all) of the revenue has not been recognized under legacy revenue guidance as of December 31, 2017. ASC 606 supersedes previous revenue recognition requirements in ASC 605 and includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the Company expects to be entitled in exchange for those goods or services.
In accordance with the adoption of ASC 606, management evaluated its contracts with customers to apply the five-step revenue recognition model. The adoption of ASC 606 did not result in a material impact to the Company’s financial position, cash flows or results of operations.
The unit of account in ASC 606 is a performance obligation, which is a promise in a contract to transfer to a customer either a distinct good or service (or bundle of goods or services) or a series of distinct goods or services provided over a period of time. ASC 606 requires that a contract’s transaction price, which is the amount of consideration to which an entity expects to be entitled in exchange for transferring promised goods or services to a customer, is to be allocated to each performance obligation in the contract based on relative standalone selling prices and recognized as revenue when (point in time) or as (over time) the performance obligation is satisfied.
Exploration and production revenues
Our exploration and production revenues are derived from contracts for oil, natural gas and natural gas liquids (“NGL”) sales, as described below. Generally, for the majority of these contracts: (i) each unit (barrel (“bbl”), mcf, gallon, etc.) of commodity product is a separate performance obligation, as our promise is to sell multiple distinct units of commodity product at a point in time; (ii) the transaction price principally consists of variable consideration, which amount is determinable each month end based on our right to invoice at month end for the value of commodity product sold to the customer that month; and (iii) the transaction price is allocated to each performance obligation based on the commodity product’s standalone selling price and recognized as revenue upon delivery of the commodity product, which is the point in time when the customer obtains control of the commodity product and our performance obligation is satisfied. The sales of oil, natural gas and NGLs as presented on the Company’s Condensed Consolidated Statements of Operations represent the Company’s share of revenues net of royalties and excluding revenue interests owned by others. When selling oil, natural gas and NGLs on behalf of royalty owners or working interest owners, the Company is acting as an agent and thus reports the revenue on a net basis. To the extent actual volumes and prices of oil and natural gas sales are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and prices for those properties are estimated and recorded. The Company’s contracts with customers typically require payments for oil, natural gas and NGL sales within 30 days following the calendar month of delivery.

7


Oil revenues. The Company sells a substantial majority of its oil through bulk sales at delivery points on crude oil gathering systems or directly at the wellhead to a variety of customers under short-term contracts that include a specified quantity of crude oil to be delivered and sold to the customer at a specified delivery point. The customer pays a market-based transaction price, which incorporates differentials that include, but are not limited to, transportation costs and adjustments for product quality.
Natural gas revenues. The Company’s natural gas sales consist of unprocessed gas sales and residue gas sales. Unprocessed gas is sold at delivery points at or near the wellhead under various contracts, in which the customer pays a transaction price based on its sale of the bifurcated NGLs and residue gas, less any associated fees. Revenue is recorded on a net basis, with processing fees deducted within revenue rather than as a separate expense line item, as title and control transfer at the delivery point. Residue gas is sold from the tailgate of the Company’s gas processing plant located in Wild Basin or transported and sold at other downstream sales points, and the customer pays a transaction price based on a market indexed per-unit rate for the quantities sold.
Purchased oil and gas sales. The Company purchases and sells crude oil and natural gas at various delivery points to a variety of customers under short-term contracts that include specified quantities of crude oil and natural gas to be sold and delivered to the customer at a specified delivery point. The Company purchases and sells crude oil and natural gas to different counterparties at market-based prices. Market-based pricing is based on the price index applicable for the location of the sale. The Company accounts for these transactions on a gross basis.
NGL revenues. NGLs are sold from the Company’s gas processing plant complex located in Wild Basin or trucked and sold at other downstream locations, and the customer pays a transaction price based on a market indexed per-unit rate for the quantities sold.
Prior period performance obligations. For sales of oil, purchased oil, natural gas, purchased gas and NGLs, the Company records revenue in the month production is delivered to the purchaser. However, settlement statements and payment may not be received for 30 to 90 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production that was delivered to the purchaser and the price that will be received for the sale of the product. The Company records the differences between estimates and the actual amounts received for product sales once payment is received from the purchaser. Such differences have historically not been significant. The Company uses knowledge of its properties, its properties' historical performance, spot market prices and other factors as the basis for these estimates. For the three and nine months ended September 30, 2018, revenue recognized related to performance obligations satisfied in prior reporting periods was not material.
Revenues associated with contracts with customers for oil, natural gas and NGL sales were as follows for the three and nine months ended September 30, 2018 and 2017:
Exploration and Production Revenues
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2018
 
2017
 
2018
 
2017
 
(In thousands)
Oil revenues
$
412,530

 
$
221,003

 
$
1,097,171

 
$
623,603

Purchased oil sales
42,902

 
20,734

 
114,598

 
56,269

Natural gas revenues
26,181

 
17,037

 
76,201

 
51,689

Purchased gas sales
1,616

 
462

 
2,161

 
648

NGL revenues
13,932

 
10,607

 
38,863

 
29,241

Total exploration and production revenues
$
497,161

 
$
269,843

 
$
1,328,994

 
$
761,450

Midstream revenues
Crude oil and natural gas revenues. The Company is party to certain contracts for gas gathering, compression, processing and gas lift services, as well as crude oil gathering, stabilization, blending, storage and transportation. Under these customer contracts, the Company provides daily integrated midstream services on a stand ready basis over a period of time, which represents a single performance obligation since the customer simultaneously receives and consumes the benefits of these services on a daily basis. Satisfaction of the Company’s performance obligation is measured as each day of service is completed, which directly corresponds with its right to consideration from the customer. Revenues associated with these contracts are recognized based upon the transaction price at month-end under the right to invoice practical expedient. Payments from customers are generally received by the Company within one month after the month in which services are provided.
Purchased oil sales. The Company purchases and sells crude oil at various delivery points on crude oil gathering systems to a variety of customers under short-term contracts that include a specified quantity of crude oil to be sold and delivered to the

8


customer at a specified delivery point. The Company purchases and sells the crude oil to different counterparties at market-based prices. Market-based pricing is based on the price index applicable for the location of the sale. The Company accounts for these transactions on a gross basis.
Water revenues. The Company is also party to certain contracts with customers for water services, which includes produced and flowback water gathering and disposal services and freshwater distribution services. Under its customer contracts for produced and flowback water gathering and disposal services, the Company provides daily integrated midstream services on a stand-ready basis over a period of time, which represents a single performance obligation since the customer simultaneously receives and consumes the benefits of these services on a daily basis. Satisfaction of the Company’s performance obligation is measured as each day of service is completed, which directly corresponds with its right to consideration from the customer. Revenues associated with these contracts are recognized based upon the transaction price at month-end under the right to invoice practical expedient. Payments from customers are generally received by the Company within one month after the month in which services are provided.
Under its customer contracts for freshwater distribution services, the Company supplies and distributes freshwater to its customers for hydraulic fracturing and production optimization. Management has determined these contracts contain multiple distinct performance obligations since each freshwater barrel is not dependent nor highly interrelated with other barrels. Revenue associated with freshwater distribution services is recognized at a point-in-time based upon the transaction price when title, control and risk of loss transfers to the customer, which occurs at the delivery point. Payments are due from customers 30 days after receipt of invoice.
Revenues associated with contracts with customers for midstream services were as follows for the three and nine months ended September 30, 2018 and 2017:
Midstream Revenues(1)
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2018
 
2017
 
2018
 
2017
 
(In thousands)
Crude oil and natural gas revenues
$
18,188

 
$
11,612

 
$
54,124

 
$
23,348

Purchased oil sales
1,838

 

 
5,212

 

Water revenues
12,999

 
7,155

 
34,327

 
25,591

Total midstream revenues
$
33,025

 
$
18,767

 
$
93,663

 
$
48,939

__________________
(1)
Represents midstream revenues, excluding all intercompany revenues, for work performed by the midstream services business segment for the Company’s working interests that are eliminated in consolidation and are therefore not included in midstream services revenues.
Well services revenues
Hydraulic fracturing service revenues. Hydraulic fracturing revenue is recognized upon the completion of each hydraulic fracturing of a well. These services are composed of various components, such as personnel, equipment and hydraulic fracturing materials, but management determined that each component is not distinct, as it cannot be used on its own or together with a resource readily available to the customer. Revenue is recognized when the performance obligations of hydraulic fracturing a well in its totality are completed; generally, this is over a period of time due to all work being performed for a customer occurring on the customer’s property, where the customer has control over the work in process as it is being performed. In addition, the Company’s assets being used to perform the obligations have no alternative use at the time of performance and the Company has the right to payment for performance to date. Payments from customers are generally received by the Company within one month after the month in which services are provided. In addition, revenue from product sales to third parties is generated when OPNA requests that third-party hydraulic fracturing companies hydraulic fracture OPNA’s wells. Although the labor is provided by the third-party hydraulic fracturing company, the materials (e.g., sand, chemicals, etc.) used in the hydraulic fracturing of the wells are provided by OWS. The third-party hydraulic fracturing company or OPNA pays OWS for the materials delivered to the wells. Revenue is recognized once the performance obligations to transfer hydraulic fracturing materials are completed.
Equipment rental revenues. Equipment rental revenue is generated when OPNA or a third-party hydraulic fracturing company rents equipment from OWS. This equipment is used in the preparation stage of hydraulic fracturing services or after the hydraulic fracturing services have been completed. Equipment rental revenues are calculated based on the equipment’s daily rental rate and the number of days that the equipment was rented by the customer. OWS’s performance obligation is satisfied when the entire rental period is completed. Equipment rental revenues are recognized over a period of time due to the customer simultaneously receiving and consuming the benefits of the rental equipment provided by OWS on a daily basis. Satisfaction of the Company’s performance obligation is measured at the completion of each day’s rental period, which directly corresponds

9


with its right to consideration from the customer. Revenues associated with these contracts are recognized at the time of invoicing for the entire rental period under the right to invoice practical expedient. Payments from customers are generally received by the Company within one month after the month in which services are provided.
Revenues associated with contracts with customers for hydraulic fracturing services and equipment rental sales were as follows for the three and nine months ended September 30, 2018 and 2017:
Well Services Revenues(1)
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2018
 
2017
 
2018
 
2017
 
(In thousands)
Hydraulic fracturing service revenues
$
14,985

 
$
15,090

 
$
42,801

 
$
31,303

Equipment rental revenues
1,277

 
1,048

 
3,543

 
2,263

Total well services revenues
$
16,262

 
$
16,138

 
$
46,344

 
$
33,566

__________________
(1)
Represents well services revenues excluding all intercompany revenues for work performed by the well services business segment for the Company’s working interests that are eliminated in consolidation and are therefore not included in well services revenues.
Contract balances
Under the Company's customer contracts, invoicing occurs once the Company's performance obligations have been satisfied, at which point payment is unconditional. Accordingly, the Company's contracts do not give rise to contract assets or liabilities under ASC 606.
Performance obligations
The majority of the Company’s sales are short-term in nature with a contract term of one year or less. For those contracts, the Company utilized the practical expedient in ASC 606-10-50-14 that exempts the Company from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less.
For the Company’s product sales that have a contract term greater than one year, the Company utilized the practical expedient in ASC 606-10-50-14(A) which states the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product generally represents a separate performance obligation; therefore future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. Under the midstream services contracts, each unit of service represents a separate performance obligation and therefore performance obligations in respect of future services are wholly unsatisfied.
4. Inventory
Crude oil inventory includes oil in tanks. Equipment and materials consist primarily of proppant, chemicals, tubular goods, well equipment to be used in future drilling or repair operations and well fracturing equipment. Crude oil inventory and equipment and materials are included in inventory on the Company’s Condensed Consolidated Balance Sheets.
The minimum volume of product in a pipeline system that enables the system to operate is known as linefill and is generally not available to be withdrawn from the pipeline system until the expiration of the transportation contract. The Company owns oil linefill in third-party pipelines, which is included in long-term inventory on the Company’s Condensed Consolidated Balance Sheets.
Inventory, including long-term inventory, is stated at the lower of cost and net realizable value with cost determined on an average cost method. The Company assesses the carrying value of inventory and uses estimates and judgment when making any adjustments necessary to reduce the carrying value to net realizable value. Among the uncertainties that impact the Company’s estimates are the applicable quality and location differentials to include in the Company’s net realizable value analysis. Additionally, the Company estimates the upcoming liquidation timing of the inventory. Changes in assumptions made as to the timing of a sale can materially impact net realizable value.

10


Total inventory consists of the following:
 
September 30, 2018
 
December 31, 2017
 
(In thousands)
Inventory
 
 
 
Crude oil inventory
$
14,867

 
$
10,427

Equipment and materials
16,542

 
8,940

Total inventory
$
31,409

 
$
19,367

 
 
 
 
Long-term inventory
 
 
 
Linefill in third-party pipelines
$
12,610

 
$
12,200

Long-term inventory
$
12,610

 
$
12,200

 
 
 
 
Total
$
44,019

 
$
31,567

5. Accounts Receivable, Net
The following table sets forth the Company’s accounts receivable, net:
 
September 30, 2018
 
December 31, 2017
 
(In thousands)
Accounts receivable, net
 
 
 
Trade accounts
$
277,558

 
$
233,660

Joint interest accounts
94,793

 
73,588

Other accounts
56,779

 
57,905

Total
429,130

 
365,153

Allowance for doubtful accounts
(946
)
 
(1,573
)
Total accounts receivable, net
$
428,184

 
$
363,580

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

11


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 September 30, 2018
 
Level 1
 
Level 2
 
Level 3
 
Total
 
(In thousands)
Assets:
 
 
 
 
 
 
 
Money market funds
$
143

 
$

 
$

 
$
143

Total assets
$
143

 
$

 
$

 
$
143

Liabilities:
 
 
 
 
 
 
 
Commodity derivative instruments (see Note 7)
$

 
$
213,146

 
$

 
$
213,146

Total liabilities
$

 
$
213,146

 
$

 
$
213,146

 
Fair value at December 31, 2017
 
Level 1
 
Level 2
 
Level 3
 
Total
 
(In thousands)
Assets:
 
 
 
 
 
 
 
Money market funds
$
142

 
$

 
$

 
$
142

Commodity derivative instruments (see Note 7)

 
353

 

 
353

Total assets
$
142

 
$
353

 
$

 
$
495

Liabilities:
 
 
 
 
 
 
 
Commodity derivative instruments (see Note 7)
$

 
$
135,567

 
$

 
$
135,567

Total liabilities
$

 
$
135,567

 
$

 
$
135,567

The Level 1 instruments presented in the tables above consist of money market funds included in cash and cash equivalents on the Company’s Condensed Consolidated Balance Sheets at September 30, 2018 and December 31, 2017. The Company’s money market funds represent cash equivalents backed by the assets of high-quality major banks and financial institutions. The Company identifies the money market funds as Level 1 instruments because the money market funds have daily liquidity, quoted prices for the underlying investments can be obtained, and there are active markets for the underlying investments.
The Level 2 instruments presented in the tables above consist of commodity derivative instruments, which include oil and natural gas swaps and collars. The fair values of the Company’s commodity derivative instruments are based upon a third-party preparer’s calculation using mark-to-market valuation reports provided by the Company’s counterparties for monthly settlement purposes to determine the valuation of its derivative instruments. The Company has the third-party preparer evaluate other readily available market prices for its derivative contracts, as there is an active market for these contracts. The third-party preparer performs its independent valuation using a moment matching method similar to Turnbull-Wakeman for Asian options. The significant inputs used are crude oil prices, volatility, skew, discount rate and the contract terms of the derivative instruments. The Company compares the third-party preparer’s valuation to counterparty valuation statements, investigating any significant differences, and analyzes monthly valuation changes in relation to movements in crude oil and natural gas forward price curves. The determination of the fair value for derivative instruments also incorporates a credit adjustment for non-performance risk, as required by GAAP. The Company calculates the credit adjustment for derivatives in a net asset position using current credit default swap values for each counterparty. The credit adjustment for derivatives in a net liability position is based on the Company’s market credit spread. Based on these calculations, the Company recorded an adjustment to reduce the fair value of its net derivative liability by $2.7 million and $2.8 million at September 30, 2018 and December 31, 2017, respectively.
There were no transfers between fair value levels during the nine months ended September 30, 2018 and December 31, 2017.

12


7. Derivative Instruments
The Company utilizes derivative financial instruments to manage risks related to changes in oil and natural gas prices. The Company’s crude oil contracts will settle monthly based on the average NYMEX West Texas Intermediate crude oil index price (“NYMEX WTI”), the average Intercontinental Exchange, Inc. Brent crude oil index price (“ICE Brent”) and the average Argus WTI Midland crude oil index price (“Midland”). The Company’s natural gas contracts will settle monthly based on the average NYMEX Henry Hub natural gas index price (“NYMEX HH”) and the average Inside FERC Northern Natural Gas Ventura natural gas index price (“IF NNG Ventura”).
At September 30, 2018, the Company utilized fixed price swaps, basis swaps and two-way and three-way costless collars to reduce the price volatility associated with certain of its of oil and natural gas sales. The Company’s fixed price swaps are comprised of a sold call and a purchased put established at the same price (both ceiling and floor), which the Company will receive for the volumes under contract. A basis swap transaction has an established fixed basis differential corresponding to two floating index prices. Depending on the difference of the two floating index prices in relation to the fixed basis differential, the Company either receives an amount from its counterparty, or pays an amount to its counterparty, equal to the difference multiplied by the hedged contract volume. A two-way collar is a combination of options: a sold call and a purchased put. The purchased put establishes a minimum price (floor) and the sold call establishes a maximum price (ceiling) the Company will receive for the volumes under contract. A three-way collar is a combination of options: a sold call, a purchased put and a sold put. The purchased put establishes a minimum price (floor), unless the market price falls below the sold put (sub-floor), at which point the minimum price would be the NYMEX index price plus the difference between the purchased put and the sold put strike price. The sold call establishes a maximum price (ceiling) the Company will receive for the volumes under contract.
All derivative instruments are recorded on the Company’s Condensed Consolidated Balance Sheets as either assets or liabilities measured at fair value (see Note 6 – Fair Value Measurements). The Company has not designated any derivative instruments as hedges for accounting purposes and does not enter into such instruments for speculative trading purposes. If a derivative does not qualify as a hedge or is not designated as a hedge, the changes in fair value are recognized in the other income (expense) section of the Company’s Condensed Consolidated Statements of Operations as a net gain or loss on derivative instruments. The Company’s cash flow is only impacted when the actual settlements under the derivative contracts result in making a payment to or receiving a payment from the counterparty. These cash settlements represent the cumulative gains and losses on the Company’s derivative instruments and do not include a recovery of costs that were paid to acquire or modify the derivative instruments that were settled. Cash settlements are reflected as investing activities in the Company’s Condensed Consolidated Statements of Cash Flows.

13


At September 30, 2018, the Company had the following outstanding commodity derivative instruments:
Commodity

Settlement
Period

Derivative
Instrument

Index
 
Volumes

Weighted Average Prices

Fair Value
Asset
(Liability)



 

Fixed Price Swaps
Basis Swaps
Sub-Floor
Floor
Ceiling

 
 
 
 
 

 
 





(In thousands)
Crude oil
 
2018
 
Fixed price swaps
 
NYMEX WTI
 
3,761,000

Bbl
 
$
52.95

 
 
 
 
 
$
(71,621
)
Crude oil
 
2018
 
Basis swaps
 
NYMEX WTI-ICE BRENT
 
152,000

Bbl
 
 
$
(9.84
)
 
 
 
 
81

Crude oil
 
2018
 
Two-way collar
 
NYMEX WTI
 
517,000

Bbl
 
 
 
 
$
58.74

$
63.94

 
(5,171
)
Crude oil
 
2019
 
Fixed price swaps
 
NYMEX WTI
 
5,613,000

Bbl
 
$
53.33

 
 
 
 
 
(99,347
)
Crude oil
 
2019
 
Basis swaps
 
NYMEX WTI-ICE BRENT
 
424,000

Bbl
 
 
$
(9.68
)
 
 
 
 
408

Crude oil
 
2019
 
Two-way collar
 
NYMEX WTI
 
3,223,000

Bbl
 
 
 
 
$
57.99

$
75.46

 
(7,580
)
Crude oil
 
2019
 
Three-way collar
 
NYMEX WTI
 
3,368,000

Bbl
 
 
 
$
40.54

$
51.03

$
68.68

 
(21,771
)
Crude oil
 
2020
 
Fixed price swaps
 
NYMEX WTI
 
403,000

Bbl
 
$
53.47

 
 
 
 
 
(5,911
)
Crude oil
 
2020
 
Two-way collar
 
NYMEX WTI
 
279,000

Bbl
 
 
 
 
$
57.78

$
76.13

 
(273
)
Crude oil
 
2020
 
Three-way collar
 
NYMEX WTI
 
279,000

Bbl
 
 
 
$
40.00

$
50.56

$
67.80

 
(1,778
)
Natural gas
 
2018
 
Fixed price swaps
 
NYMEX HH
 
3,496,000

MMbtu
 
$
3.01

 
 
 
 
 
(104
)
Natural gas
 
2018
 
Basis swaps
 
IF NNG VENTURA-NYMEX HH
 
1,225,000

MMbtu
 
 
$
(0.05
)
 
 
 
 
(64
)
Natural gas
 
2019
 
Fixed price swaps
 
NYMEX HH
 
1,896,000

MMbtu
 
$
2.95

 
 
 
 
 
16

Natural gas
 
2019
 
Basis swaps
 
IF NNG VENTURA-NYMEX HH
 
2,715,000

MMbtu
 
 
$
(0.05
)
 
 
 
 
(31
)






 
 




 




$
(213,146
)
In October 2018, the Company entered into new swaps and two-way costless collar options for crude oil and natural gas with weighted average floor prices of $64.05 per barrel and $2.88 per MMbtu, respectively. The commodity contracts included total notional amounts of 213,000 barrels, 792,000 barrels and 62,000 barrels which settle in 2018, 2019 and 2020, respectively, based on NYMEX WTI and 305,000 MMbtu and 1,825,000 MMbtu which settle in 2018 and 2019, respectively, based on NYMEX HH. Additionally, the Company entered into new basis swap contracts for crude and natural gas with weighted average differential prices, which represent a reduction of $7.50 per barrel and an addition of $0.13 per MMbtu, respectively. The crude basis swap contracts include total notional amounts of 60,000 barrels and 424,000 barrels, which settle in 2018 and 2019, respectively, based on the differential between Midland and NYMEX WTI, and the natural gas basis swap contracts include total notional amounts of 610,000 MMbtu and 1,810,000 MMbtu, which settle in 2018 and 2019, respectively, based on the differential between IF NNG Ventura and NYMEX HH. These derivative instruments do not qualify for and were not designated as hedging instruments for accounting purposes.
The following table summarizes the location and amounts of gains and losses from the Company’s commodity derivative instruments recorded in the Company’s Condensed Consolidated Statements of Operations for the periods presented:
 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
Statements of Operations Location
 
2018
 
2017
 
2018
 
2017
 
 
(In thousands)
Net gain (loss) on derivative instruments
 
$
(48,544
)
 
$
(54,310
)
 
$
(239,945
)
 
$
52,297

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

14


The following table summarizes the location and fair value of all outstanding commodity derivative instruments recorded in the Company’s Condensed Consolidated Balance Sheets: 
 
 
 
 
September 30, 2018
Commodity
 
Balance Sheet Location
 
Gross Recognized Liabilities
 
Gross Amount Offset
 
Net Recognized Fair Value Liabilities
 
 
 
 
(In thousands)
Derivatives liabilities:
 
 
 
 
 
 
 
 
Commodity contracts
 
Derivative instruments — current liabilities
 
$
184,832

 
$
(4,703
)
 
$
180,129

Commodity contracts
 
Derivative instruments — non-current liabilities
 
37,006

 
(3,989
)
 
33,017

Total derivatives liabilities
 
$
221,838

 
$
(8,692
)
 
$
213,146

 
 
 
 
 
 
 
 
 
 
 
 
 
December 31, 2017
Commodity
 
Balance Sheet Location
 
Gross Recognized Assets/Liabilities
 
Gross Amount Offset
 
Net Recognized Fair Value Assets/Liabilities
 
 
 
 
(In thousands)
Derivatives assets:
 
 
 
 
 
 
 
 
Commodity contracts
 
Derivative instruments — current assets
 
$
344

 
$

 
$
344

Commodity contracts
 
Derivative instruments — non-current assets
 
9

 

 
9

Total derivatives assets
 
$
353

 
$

 
$
353

Derivatives liabilities:
 
 
 
 
 
 
 
 
Commodity contracts
 
Derivative instruments — current liabilities
 
$
117,629

 
$
(1,913
)
 
$
115,716

Commodity contracts
 
Derivative instruments — non-current liabilities
 
20,035

 
(184
)
 
19,851

Total derivatives liabilities
 
$
137,664

 
$
(2,097
)
 
$
135,567

8. Property, Plant and Equipment
The following table sets forth the Company’s property, plant and equipment:
 
September 30, 2018
 
December 31, 2017
 
(In thousands)
Proved oil and gas properties(1)
$
7,566,694

 
$
7,058,782

Less: Accumulated depreciation, depletion, amortization and impairment
(2,689,613
)
 
(2,395,153
)
Proved oil and gas properties, net
4,877,081

 
4,663,629

Unproved oil and gas properties
1,104,450

 
780,173

Other property and equipment
1,088,781

 
868,746

Less: Accumulated depreciation
(170,175
)
 
(139,062
)
Other property and equipment, net
918,606

 
729,684

Total property, plant and equipment, net
$
6,900,137

 
$
6,173,486

__________________
(1)
Included in the Company’s proved oil and gas properties are estimates of future asset retirement costs of $41.4 million and $39.9 million at September 30, 2018 and December 31, 2017, respectively.
9. Acquisition
Permian Basin Acquisition. On February 14, 2018, the Company acquired from Forge Energy, LLC (“Forge Energy”) approximately 22,000 net acres in the Delaware Basin (the “Permian Basin Acquisition”) for aggregate consideration consisting of approximately $549.8 million in cash and 46,000,000 shares of the Company’s common stock, subject to customary post-closing adjustments (collectively, the “Purchase Price”). In connection with the closing of the Permian Basin Acquisition, the Company and Forge Energy entered into a Registration Rights Agreement that granted the equity holders of Forge Energy certain customary registration rights for the stock portion of the Purchase Price. The Company funded the cash portion of the Purchase Price with borrowings under a senior secured revolving line of credit among OPNA, as Borrower, Wells Fargo Bank,

15


N.A., as administrative agent and the lenders party thereto (the “Oasis Credit Facility”), and proceeds from the Company’s December 2017 issuance of its common stock.
The Permian Basin Acquisition represents the Company’s initial entry into the Delaware Basin. The assets underlying the Permian Basin Acquisition are primarily located in the Bone Spring and Wolfcamp formations of the Delaware sub-basin, across Ward, Winkler, Loving and Reeves Counties, Texas.
The Permian Basin Acquisition qualified as a business combination. As such, the Company estimated the fair value of the assets acquired and liabilities assumed as of the February 14, 2018 acquisition date. The 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). Fair value measurements also utilize assumptions of market participants. The Company used a discounted cash flow model and made market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates. These assumptions represent Level 3 inputs, as further discussed under Note 6Fair Value Measurements. The Company recorded the assets acquired and liabilities assumed in the Permian Basin Acquisition at their estimated fair value of $921.0 million, which the Company considers to be representative of the price paid by a typical market participant. This measurement resulted in no goodwill or bargain purchase being recognized. The Permian Basin Acquisition is considered a taxable transaction; therefore, no deferred tax amounts were recognized at the acquisition date as the tax basis of the assets acquired and liabilities assumed were also recorded at fair value.
The following table summarizes the consideration paid for the Company’s acquisition and the fair value of the assets acquired and liabilities assumed as of the acquisition date.
 
At February 14, 2018
 
(In thousands)
Consideration paid to Forge Energy:
 
Cash
$
549,770

Common stock: 46,000,000 shares issued
371,220

 
$
920,990

Recognized amounts of identifiable assets acquired and liabilities assumed:
 
Proved developed properties
$
110,325

Proved undeveloped properties
166,552

Unproved lease acquisition costs
645,068

Inventory
293

Intangible assets
1,000

Asset retirement obligations
(2,248
)
 
$
920,990

The results of operations for the Permian Basin Acquisition have been included in the Company’s condensed consolidated financial statements since the February 14, 2018 closing date, including $19.4 million and $51.0 million of total revenue and $3.9 million and $14.2 million of operating income for the three and nine months ended September 30, 2018, respectively.
The Company also recorded a $1.0 million finite-lived intangible asset on the Company’s Condensed Consolidated Balance Sheets for a non-compete agreement with a one-year life. Intangible assets are amortized on a straight-line basis over the useful life, and the Company includes the amortization in depreciation, depletion and amortization expenses on the Company’s Condensed Consolidated Statements of Operations. For the three and nine months ended September 30, 2018, amortization expense recognized for this non-compete agreement was approximately $0.3 million and $0.6 million, respectively.
Summarized below are the consolidated results of operations for the three and nine months ended September 30, 2018, on an unaudited pro forma basis, as if the acquisition and related financing had occurred on January 1, 2017. The unaudited pro forma financial information was derived from the historical consolidated statements of operations of the Company and the statement of revenues and direct operating expenses for the Permian Basin Acquisition properties, which were derived from the historical accounting records of Forge Energy. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the acquisition and related financing occurred on the basis assumed above, nor is such information indicative of the Company’s expected future results of operations.

16


 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2018
 
2017
 
2018
 
2017
 
(In thousands)
 
(In thousands)
 
Unaudited
 
Unaudited
Revenues
$
546,449

 
$
318,879

 
$
1,474,530

 
$
871,952

Net income (loss) attributable to Oasis
62,341

 
(29,717
)
 
(252,731
)
 
22,068

 
 
 
 
 
 
 
 
Net income (loss) attributable to Oasis per share:
 
 
 
 
 
 
 
Basic
$
0.20

 
$
(0.11
)
 
$
(0.81
)
 
$
0.08

Diluted
0.20

 
(0.11
)
 
(0.81
)
 
0.08

Other Delaware AcquisitionOn September 12, 2018, the Company completed the initial closing with undisclosed sellers to acquire certain exploration and production assets adjacent to the Company’s existing Delaware position (the “Other Delaware Acquisition”) for total cash consideration of $59.5 million. Based on the FASB’s authoritative guidance, the acquisition qualified as a business combination, and as such, the Company estimated the fair value of the assets acquired as of the acquisition date. The Company recorded the oil and gas properties acquired at their estimated fair value of $59.5 million, which the Company considers to be representative of the price paid by a typical market participant. This measurement resulted in no goodwill or bargain purchase being recognized.
The results of operations for the acquisition have been included in the Company’s consolidated financial statements since the closing date. Pro forma information is not presented as the pro forma results would not be materially different from the information presented in the Company’s Consolidated Statement of Operations.
10. Divestitures
Williston Non-Op Divestiture. On July 10, 2018, the Company completed the initial closing for the sale of certain non-operated oil and gas properties in the Williston Basin (the “Williston Non-Op Divestiture”). The transaction had an effective date of March 1, 2018, and the final closing statement will be completed in the fourth quarter of 2018. Upon the initial closing, the Company recognized a $27.5 million net gain on sale of properties, which is subject to customary closing adjustments, in its Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2018. The divested properties were in the Company’s exploration and production segment.
Foreman Butte Divestiture. On July 31, 2018, the Company completed the initial closing for the sale of oil and gas properties and certain other property and equipment primarily located in the Foreman Butte area of the Williston Basin (the “Foreman Butte Divestiture”). The transaction had an effective date of March 1, 2018, and the final closing statement will be completed in the first quarter of 2019. During the second quarter of 2018, the Company recorded an impairment loss of $383.4 million, which was included in impairment on the Company’s Condensed Consolidated Statements of Operations, to adjust the carrying value of these assets to their estimated fair value, determined based on the expected sales price as negotiated with the purchaser, less costs to sell. Upon the initial closing, the Company recognized a $10.1 million net loss on sale of properties, which is subject to customary closing adjustments, in its Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2018. The Foreman Butte Divestiture 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.
Other Williston Divestiture. On August 17, 2018, the Company completed the initial closing for the sale of additional non-strategic oil and gas properties in the Williston Basin (the “Other Williston Divestiture”). The transaction had an effective date of March 1, 2018, and the final closing statement will be completed in the first quarter of 2019. Upon the initial closing, the Company recognized a $19.4 million net gain on sale of properties, which is subject to customary closing adjustments, in its Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2018. The divested properties were in the Company’s exploration and production segment.

17


11. Long-Term Debt
The Company’s long-term debt consists of the following:
 
September 30, 2018
 
December 31, 2017
 
(In thousands)
Oasis Credit Facility
$
522,000

 
$
70,000

OMP Credit Facility
166,000

 
78,000

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

 
54,275

6.50% senior unsecured notes due November 1, 2021
71,835

 
395,501

6.875% senior unsecured notes due March 15, 2022
901,480

 
937,080

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

 
366,094

6.25% senior unsecured notes due May 1, 2026
400,000

 

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

 
300,000

Total principal of senior unsecured notes
2,039,409

 
2,052,950

Less: unamortized deferred financing costs on senior unsecured notes
(22,212
)
 
(22,956
)
Less: unamortized debt discount on senior unsecured convertible notes
(72,188
)
 
(80,388
)
Total long-term debt
$
2,633,009

 
$
2,097,606

The carrying amount of the Company’s long-term debt reported in the Condensed Consolidated Balance Sheet at September 30, 2018 was $2,633.0 million, which included $2,039.4 million of senior unsecured notes, reductions for the unamortized debt discount related to the equity component of the senior unsecured convertible notes and the unamortized deferred financing costs on the senior unsecured notes of $72.2 million and $22.2 million, respectively, $522.0 million of borrowings under the Oasis Credit Facility and $166.0 million of borrowings under a $250.0 million senior secured revolving credit facility among OMP, as parent, OMP Operating LLC, a subsidiary of OMP, as borrower, Wells Fargo Bank, N.A., as administrative agent and the lenders party thereto (the “OMP Credit Facility,” and, together with the Oasis Credit Facility, the “Revolving Credit Facilities”). The Revolving Credit Facilities are recorded at values that approximate fair value since their variable interest rates are tied to current market rates. The fair value of the Company’s senior unsecured notes, which are publicly traded and therefore categorized as Level 1 liabilities, was $2,172.3 million at September 30, 2018.
Senior secured revolving line of credit. The Company has the Oasis Credit Facility with an overall senior secured line of credit of $2,500.0 million as of September 30, 2018, which has a maturity date of April 13, 2020. The Oasis 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 26, 2018, the Company entered into an amendment to the Oasis Credit Facility, resulting in the aggregate elected commitment being increased from $1,150.0 million to $1,350.0 million and two new lenders being added to the bank group. On April 19, 2018, the lenders under the Oasis Credit Facility completed their regular semi-annual redetermination of the borrowing base scheduled for April 1, 2018, resulting in the Company entering into the Twelfth Amendment to the Second Amended and Restated Credit Agreement to the Oasis Credit Facility, which (i) reaffirmed the borrowing base and the aggregate elected commitment at $1,600.0 million and $1,350.0 million, respectively, (ii) removed the legacy anti-cash hoarding provisions, (iii) reduced the coverage threshold with respect to mortgaged properties and (iv) amended the asset sale covenant to give the Company additional flexibility to trade oil and gas properties. In addition, in connection with such amendment, OP Permian became a guarantor under the Oasis Credit Facility.
On October 16, 2018, the Company entered into a third amended and restated credit agreement (the “Third Amended Credit Facility”). In connection with entry into the Third Amended Credit Facility, the semi-annual redetermination of the Company’s borrowing base was completed on October 16, 2018, which reaffirmed the borrowing base and the aggregate elected commitment at $1,600.0 million and $1,350.0 million, respectively, and the overall credit facility increased from $2,500.0 million to $3,000.0 million. Pursuant to the Third Amended Credit Facility, the credit facility was extended from April 2020 to October 2023, provided that the Company’s 2022 and 2023 Senior Notes are retired or refinanced 90 days prior to their respective maturities. All other significant rates, terms and conditions of the Third Amended Credit Facility remained the same. The next redetermination of the Oasis Credit Facility’s borrowing base is scheduled for April 1, 2019.
At September 30, 2018, the Company had $522.0 million of London Interbank Offered Rate (“LIBOR”) loans at a weighted average interest rate of 3.9% and $14.0 million of outstanding letters of credit issued under the Oasis Credit Facility, resulting in an unused borrowing base committed capacity of $814.0 million. On a quarterly basis, the Company also pays a commitment fee that can range from 0.375% to 0.500% on the average amount of borrowing base capacity not utilized during the quarter

18


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 Oasis Credit Facility as of September 30, 2018.
OMP Operating LLC revolving line of credit. Through its ownership of OMP, the Company has access to the OMP Credit Facility with a revolving line of credit of $250.0 million, which has a maturity date of September 25, 2022. On August 27, 2018, OMP entered into an amendment to its revolving credit facility to the OMP Credit Facility in order to (i) increase the aggregate amount of commitments from $200.0 million to $250.0 million, (ii) provide for the ability to further increase commitments and (iii) add six new lenders to the bank group. The OMP Credit Facility is available to fund working capital and to finance acquisitions and other capital expenditures of OMP. The OMP Credit Facility includes a letter of credit sublimit of $10.0 million and a swingline loans sublimit of $10.0 million. The borrowing capacity on the OMP Credit Facility may be increased up to $400.0 million, subject to certain conditions.
Borrowings under the OMP Credit Facility bear interest at a rate per annum equal to the applicable margin (as described below) plus (i) with respect to Eurodollar Loans, the Adjusted LIBO Rate (as defined in the OMP Credit Facility) or (ii) with respect to ABR Loans, the greatest of (A) the Prime Rate in effect on such day, (B) the Federal Funds Effective Rate in effect on such day plus 1/2 of 1.00% or (C) the Adjusted LIBO Rate for a one-month interest period on such day plus 1.00% (each as defined in the OMP Credit Facility). The applicable margin for borrowings under the OMP Credit Facility varies from (a) in the case of Eurodollar Loans, 1.75% to 2.75% and (b) in the case of ABR Loans or swingline loans, 0.75% to 1.75%. The unused portion of the OMP Credit Facility is subject to a commitment fee ranging from 0.375% to 0.500%.
The OMP Credit Facility includes certain financial covenants as of the end of each fiscal quarter, including a (i) consolidated leverage ratio, (ii) consolidated secured leverage ratio and (iii) consolidated interest coverage ratio (each covenant as described in the OMP Credit Facility). OMP Operating LLC was in compliance with the financial covenants of the OMP Credit Facility as of September 30, 2018. All obligations of OMP Operating LLC, as the borrower under the OMP Credit Facility, are unconditionally guaranteed on a joint and several basis by OMP, OMP Operating LLC and Bighorn DevCo LLC.
At September 30, 2018, the Company had $166.0 million of borrowings outstanding under the OMP Credit Facility. As of September 30, 2018, the weighted average interest rate on borrowings under the OMP Credit Facility was 4.0%.
Senior unsecured notes. On May 14, 2018, the Company completed its offering of $400.0 million in aggregate principal amount of its 6.25% senior unsecured notes due 2026 (the “2026 Notes”). The Company used the net proceeds of $394.4 million from the 2026 Notes to fund the repurchase of certain outstanding senior notes (the “Tender Offers”), as described below. At September 30, 2018, the Company had $1,739.4 million principal amount of senior unsecured notes outstanding with maturities ranging from November 2021 to May 2026 and coupons ranging from 6.25% to 6.875% (the “Senior Notes”). Prior to certain dates, the Company has the option to redeem some or all of the Senior Notes for cash at certain redemption prices equal to a certain percentage of their principal amount plus an applicable make-whole premium and accrued and unpaid interest to the redemption date.
On May 25, 2018, the Company completed the Tender Offers and, as a result of the Tender Offers, the Company repurchased an aggregate principal amount of $390.6 million of its outstanding Senior Notes, consisting of $31.3 million principal amount of its 7.25% senior unsecured notes due 2019 (the “2019 Notes”), $323.7 million principal amount of its 6.50% senior unsecured notes due 2021 and $35.6 million principal amount of its 6.875% senior unsecured notes due 2022, for an aggregate cost of $402.0 million, including accrued interest and fees.
On May 29, 2018, the Company paid $23.0 million to redeem all of the remaining outstanding 2019 Notes, which payment consisted of the 100% redemption price plus all accrued and unpaid interest on the 2019 Notes. The Company financed the redemption with borrowings under the Oasis Credit Facility. As a result of the Tender Offers and the redemption, the Company recognized a pre-tax loss of $13.7 million, which was net of unamortized deferred financing costs write-offs of $4.0 million, and is reflected in loss on extinguishment of debt in the Company’s Condensed Consolidated Statements of Operations for the nine months ended September 30, 2018. As of September 30, 2018, no 2019 Notes remained outstanding.
Senior unsecured convertible notes. At September 30, 2018, the Company had 300.0 million of 2.625% senior unsecured convertible notes due September 2023 (the “Senior Convertible Notes”). The Company has the option to settle conversions of these notes with cash, shares of common stock or a combination of cash and common stock at its election. The Company’s intent is to settle the principal amount of the Senior Convertible Notes in cash upon conversion. Prior to March 15, 2023, the Senior Convertible Notes will be convertible only under the following circumstances: (i) during any calendar quarter (and only during such calendar quarter), if the last reported sale price of the Company’s common stock for at least 20 trading days (whether or not consecutive) during the period of 30 consecutive trading days ending on the last trading day of the immediately preceding calendar quarter is greater than or equal to 130% of the conversion price on each applicable trading day; (ii) during the five business day period after any five consecutive trading day period (the “Measurement Period”) in which the trading price per $1,000 principal amount of the Senior Convertible Notes for each trading day of the Measurement Period is less than 98% of the product of the last reported sale price of the Company’s common stock and the conversion rate on each such trading day; or (iii) upon the occurrence of specified corporate events, including certain distributions or a fundamental change. On or

19


after March 15, 2023, the Senior Convertible Notes will be convertible at any time until the second scheduled trading day immediately preceding their September 15, 2023 maturity date. The Senior Convertible Notes will be convertible at an initial conversion rate of 76.3650 shares of the Company’s common stock per $1,000 principal amount of the Senior Convertible Notes, which is equivalent to an initial conversion price of approximately $13.10. The conversion rate will be subject to adjustment in some events but will not be adjusted for any accrued and unpaid interest. In addition, following certain corporate events that occur prior to the maturity date or a notice of redemption, the Company will increase the conversion rate for a holder who elects to convert its Senior Convertible Notes in connection with such corporate event or redemption in certain circumstances. As of September 30, 2018, none of the contingent conditions allowing holders of the Senior Convertible Notes to convert these notes had been met.
Upon issuance, the Company separately accounted for the liability and equity components of the Senior Convertible Notes in accordance with Accounting Standards Codification 470-20. The liability component was recorded at the estimated fair value of a similar debt instrument without the conversion feature. The difference between the principal amount of the Senior Convertible Notes and the estimated fair value of the liability component was recorded as a debt discount and will be amortized to interest expense over the term of the notes using the effective interest method, with an effective interest rate of 8.97% per annum. The fair value of the Senior Convertible Notes as of the issuance date was estimated at $206.8 million, resulting in a debt discount at inception of $93.2 million. The equity component, representing the value of the conversion option, was computed by deducting the fair value of the liability component from the initial proceeds of the Senior Convertible Notes issuance. This equity component was recorded, net of deferred taxes and issuance costs, in additional paid-in capital and will not be remeasured as long as it continues to meet the conditions for equity classification. 
Interest on the Senior Notes and the Senior Convertible Notes (collectively, the “Notes”) is payable semi-annually in arrears. The Notes are guaranteed on a senior unsecured basis by the Company, along with its material subsidiaries (the “Guarantors”), which are 100% owned by the Company. These guarantees are full and unconditional and joint and several among the Guarantors, subject to certain customary release provisions. The indentures governing the Notes contain customary events of default as well as covenants that place restrictions on the Company and certain of its subsidiaries.
12. Asset Retirement Obligations
The following table reflects the changes in the Company’s ARO during the nine months ended September 30, 2018:
 
(In thousands)
Balance at December 31, 2017
$
48,799

Liabilities incurred during period
5,509

Liabilities settled during period
(4,904
)
Accretion expense during period(1)
1,975

Revisions to estimates
83

Balance at September 30, 2018
$
51,462

___________________
(1)
Included in depreciation, depletion and amortization on the Company’s Condensed Consolidated Statements of Operations.
At September 30, 2018, the current portion of the total ARO balance was approximately $0.1 million and was included in accrued liabilities on the Company’s Condensed Consolidated Balance Sheets.
13. Income Taxes
The Company’s effective tax rate for the three and nine months ended September 30, 2018 was 27.2% and 23.4%, respectively, as compared to an effective tax rate of 31.5% and 41.2% for the three and nine months ended September 30, 2017, respectively. The effective tax rate for the three months ended September 30, 2018 was higher than the statutory federal rate of 21% primarily due to state income taxes and the impact of non-deductible executive compensation. The effective tax rate for the nine months ended September 30, 2018 was higher than the statutory rate primarily due to state income taxes and the impact of a change in the blended state rate at which the Company’s deferred taxes are recorded, partially offset by the impact of non-deductible executive compensation.
The effective tax rate for the three months ended September 30, 2017 was lower than the statutory federal rate of 35% primarily due to the impact of non-deductible executive compensation and equity-based compensation shortfalls, partially offset by state income taxes. The effective tax rate for the nine months ended September 30, 2017 was higher than the statutory federal rate of 35% primarily due to state income taxes, the impact of non-deductible executive compensation and equity-based compensation

20


windfalls, partially offset by the portion of OMP’s earnings attributable to the non-controlling public limited partners, which are not taxable to the Company.
Valuation allowance. The Company had valuation allowances of $3.3 million and $1.2 million as of September 30, 2018 and December 31, 2017, respectively, because the Company has concluded it is more likely than not that it will be unable to utilize certain state net operating loss carryforwards and charitable contribution carryforwards. As of each reporting date, the Company’s management considers new evidence, both positive and negative, which could impact management’s view with regard to future realization of deferred tax assets. During the nine months ended September 30, 2018, the valuation allowance was increased by $2.1 million, primarily against the Company’s Montana net operating loss carryforwards, as a result of the Permian Basin Acquisition and the corresponding shift of projected future taxable income into other states. During the three months ended September 30, 2018, there was no material change to the valuation allowance.
Tax Cuts and Jobs Act. On December 22, 2017, the U.S. government enacted the Tax Act, which made broad and complex changes to the U.S. tax code. Due to the complexities involved in the accounting for the enactment of the new law, the SEC issued SAB 118, which provides guidance on the accounting for the tax effects of the Tax Act. SAB 118 provides a measurement period that should not extend beyond one year from the Tax Act enactment date to complete the accounting under ASC 740, "Income Taxes." In accordance with SAB 118, the Company was able to make reasonable estimates on certain effects of the Tax Act in the financial statements as of December 31, 2017. During the three months ended September 30, 2018, the Company completed the accounting under the Tax Act. Based on additional guidance issued by the Internal Revenue Service regarding the grandfather provisions related to certain performance-based compensation awards outstanding as of November 2, 2017, the Company wrote off $1.9 million of deferred tax assets for which the Company will not receive a future tax deduction.
14. Equity-Based Compensation
Restricted stock awards. The Company has granted restricted stock awards to employees and directors under its Amended and Restated 2010 Long Term Incentive Plan, the majority of which vest over a three-year period. The fair value of restricted stock awards is based on the closing sales price of the Company’s common stock on the date of grant. Compensation expense is recognized ratably over the requisite service period.
During the nine months ended September 30, 2018, employees and non-employee directors of the Company were granted restricted stock awards equal to 3,511,030 shares of common stock with a $10.17 weighted average grant date per share value. Equity-based compensation expense recorded for restricted stock awards for the three and nine months ended September 30, 2018 was $5.1 million and $14.7 million, respectively, and $4.9 million and $15.2 million for the three and nine months ended September 30, 2017, respectively. Equity-based compensation expense is included in general and administrative expenses on the Company’s Condensed Consolidated Statements of Operations.
Performance share units. The Company has granted performance share units (“PSUs”) to officers of the Company under its Amended and Restated 2010 Long Term Incentive Plan. The PSUs are awards of restricted stock units, and each PSU that is earned represents the right to receive one share of the Company’s common stock.
The Company accounts for PSUs as equity awards pursuant to the FASB’s authoritative guidance for share-based payments. The number of PSUs to be earned is subject to a market condition, which is based on a comparison of the total shareholder return (“TSR”) achieved with respect to shares of the Company’s common stock against the TSR achieved by a defined peer group at the end of the performance periods. Depending on the Company’s TSR performance relative to the defined peer group, award recipients will earn between 0% and 200% of the initial PSUs granted. All compensation expense related to the PSUs will be recognized if the requisite performance period is fulfilled, even if the market condition is not achieved.
The aggregate grant date fair value of the market-based awards was determined using a Monte Carlo simulation model. The Monte Carlo simulation model uses assumptions regarding random projections and must be repeated numerous times to achieve a probabilistic assessment. The key valuation assumptions for the Monte Carlo model are the forecast period, initial value, stock price on the date of grant, risk-free interest rate, volatility and correlation coefficients. The risk-free interest rates are the U.S. Treasury bond rates on the date of grant that correspond to each performance period. The initial value is the average of the volume weighted average prices for the 30 trading days prior to the start of the performance cycle for the Company and each of its peers. Volatility was calculated from the daily historical returns of stock prices over a historical period for the Company and each of its peers. The correlation coefficients are measures of the strength of the linear relationship between and amongst the Company and its peers estimated based on historical stock price data.
The following assumptions were used for the Monte Carlo model to determine the grant date fair value and associated equity-based compensation expense of the PSUs granted during the nine months ended September 30, 2018:

21


Risk-free interest rate
2.08% - 2.31%

Oasis volatility
72.88
%
Oasis initial value
$8.82
Oasis stock price on date of grant
$9.27
During the nine months ended September 30, 2018, officers of the Company were granted 854,400 PSUs with a $12.71 weighted average grant date per unit value. Equity-based compensation expense recorded for PSUs for the three and nine months ended September 30, 2018 was $2.2 million and $6.3 million, respectively, and $1.6 million and $5.1 million for the three and nine months ended September 30, 2017, respectively. Equity-based compensation expense is included in general and administrative expenses on the Company’s Condensed Consolidated Statements of Operations.
OMP phantom unit awards. The Company has granted OMP phantom unit awards (collectively, the “OMP Phantom Unit Awards,” and each an “OMP Phantom Unit”) to employees under its Amended and Restated 2010 Long Term Incentive Plan in 2018, and in 2017, under OMP GP’s Oasis Midstream Partners LP 2017 Long Term Incentive Plan (“OMP LTIP”).
Each OMP Phantom Unit represents the right to receive, upon vesting of the award, a cash payment equal to the fair market value of one OMP common unit on the day prior to the date it vests (the “Vesting Date”). Award recipients are also entitled to Distribution Equivalent Rights (“DER”) with respect to each OMP Phantom Unit received. Each DER represents the right to receive, upon vesting of the award, a cash payment equal to the value of the distributions paid on one OMP common unit between the Grant Date and the applicable Vesting Date. The OMP Phantom Unit Awards vest in equal amounts each year over a three-year period, and compensation expense will be recognized over the requisite service period and is included in general and administrative expenses on the Company’s Condensed Consolidated Statements of Operations.
The OMP Phantom Unit Awards are accounted for as liability-classified awards since the awards will settle in cash, and equity-based compensation cost is accounted for under the fair value method in accordance with GAAP. Under the fair value method for liability-classified awards, compensation cost is remeasured each reporting period at fair value based upon the closing price of a publicly traded common unit. The Company will directly pay, or will reimburse OMP, for the cash settlement amount of these awards.
During the nine months ended September 30, 2018, the Company granted 87,480 OMP Phantom Unit Awards to certain employees of Oasis. Equity-based compensation expense recorded for the OMP Phantom Unit Awards for the three and nine months ended September 30, 2018 was $0.2 million and $0.4 million, respectively. The Company did not record any equity-based compensation related to the OMP Phantom Unit Awards for the three and nine months ended September 30, 2017 because these awards were first granted in the fourth quarter of 2017.
OMP restricted unit awards. During the nine months ended September 30, 2018, independent directors of OMP were granted 17,260 restricted unit awards which vest over a one-year period with a weighted average grant date fair value of $17.55 per common unit. These awards are accounted for as equity-classified awards since the awards will settle in common units upon vesting. Equity-based compensation cost is accounted for under the fair value method in accordance with GAAP. Under the fair value method for equity-classified awards, compensation cost is measured at the grant date based on the fair value of the award and is recognized over the vesting period. Compensation cost associated with these awards was approximately $0.1 million and $0.3 million for the three and nine months ended September 30, 2018, respectively, and is included in general and administrative expenses on the Company’s Condensed Consolidated Statements of Operations.
15. Earnings (Loss) Per Share
Basic earnings (loss) per share is computed by dividing the earnings (loss) attributable to Oasis common stockholders by the weighted average number of shares outstanding for the periods presented. The calculation of diluted earnings (loss) per share includes the potential dilutive impact of unvested restricted stock awards and contingently issuable shares related to PSUs and the Senior Convertible Notes during the periods presented, unless their effect is anti-dilutive. There are no adjustments made to the income (loss) attributable to Oasis available to common stockholders in the calculation of diluted earnings (loss) per share.

22


The following is a calculation of the basic and diluted weighted average shares outstanding for the three and nine months ended September 30, 2018 and 2017: 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2018
 
2017
 
2018
 
2017
 
(In thousands)
Basic weighted average common shares outstanding
313,167

 
233,389

 
305,533

 
233,248

Dilutive effect of restricted stock awards and PSUs(1)
3,220

 

 

 

Diluted weighted average common shares outstanding
316,387

 
233,389

 
305,533

 
233,248

__________________ 
(1)
No unvested stock awards were included in computing earnings (loss) per share for the nine months ended September 30, 2018 and the three and nine months ended September 30, 2017 because the effects were anti-dilutive.
For the nine months ended September 30, 2018 and the three and nine months ended September 30, 2017, the Company incurred a net loss, and therefore the diluted loss per share calculation for the period excludes the anti-dilutive effect of unvested stock awards. In addition, the Company excluded these unvested stock awards from the diluted earnings (loss) per share calculation for the three months ended September 30, 2018 because the effects were anti-dilutive based on the treasury stock method. The following is a calculation of weighted average common shares excluded from diluted earnings (loss) per share due to the anti-dilutive effect:
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2018
 
2017
 
2018
 
2017
 
(In thousands)
Restricted stock awards and PSUs
4,180

 
5,841

 
7,284

 
5,988

The Company issued its Senior Convertible Notes in September 2016 (see Note 11 – Long-Term Debt). The Company has the option to settle conversions of its Senior Convertible Notes with cash, shares of common stock or a combination of cash and common stock at its election. The Company’s intent is to settle the principal amount of the Senior Convertible Notes in cash upon conversion. As a result, only the amount by which the conversion value exceeds the aggregate principal amount of the notes (conversion spread) is considered in the diluted earnings per share computation under the treasury stock method. As of September 30, 2018, the conversion value did not exceed the principal amount of the notes, and accordingly, there was no impact to diluted earnings per share for the three and nine months ended September 30, 2018.
16. Business Segment Information
The Company’s exploration and production segment is engaged in the acquisition and development of oil and natural gas properties. Revenues for the exploration and production segment are derived from the sale of oil and natural gas production. The Company’s midstream services business segment (“OMS”) performs produced and flowback water gathering and disposal services, fresh water services, natural gas gathering and processing and crude oil gathering and transportation and other midstream services for the Company’s oil and natural gas wells operated by OPNA and other third-party operators. Revenues for the midstream segment are primarily derived from produced and flowback water pipeline transport, produced and flowback water disposal, fresh water sales, natural gas gathering and processing and crude oil gathering, blending, stabilization and transportation. The Company’s well services business segment (“OWS”) performs completion services for the Company’s oil and natural gas wells operated by OPNA. Revenues for the well services segment are derived from providing well services, product sales and equipment rentals. The revenues and expenses related to work performed by OMS and OWS for OPNA’s working interests are eliminated in consolidation, and only the revenues and expenses related to non-affiliated working interest owners are included in the Company’s Condensed Consolidated Statements of Operations. These segments represent the Company’s three operating units, each offering different products and services. The Company’s corporate activities have been allocated to the supported business segments accordingly.
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 (“DD&A”). The following table summarizes financial information for the Company’s three business segments for the periods presented:

23


 
Exploration and
Production
 
Midstream Services
 
Well Services
 
Eliminations
 
Consolidated
 
(In thousands)
Three months ended September 30, 2018:
 
Revenues from non-affiliates
$
497,161

 
$
33,025

 
$
16,262

 
$

 
$
546,448

Inter-segment revenues

 
42,745

 
40,177

 
(82,922
)
 

Total revenues
497,161

 
75,770

 
56,439

 
(82,922
)
 
546,448

Operating income
146,969

 
31,326

 
9,237

 
(8,487
)
 
179,045

Other expense
(87,594
)
 
(367
)
 
(79
)
 

 
(88,040
)
Income before income taxes including non-controlling interests
$
59,375

 
$
30,959

 
$
9,158

 
$
(8,487
)
 
$
91,005

 
 
Three months ended September 30, 2017:
 
Revenues from non-affiliates
$
269,843

 
$
18,767

 
$
16,138

 
$

 
$
304,748

Inter-segment revenues

 
28,893

 
31,025

 
(59,918
)
 

Total revenues
269,843

 
47,660

 
47,163

 
(59,918
)
 
304,748

Operating income
3,484

 
25,194

 
10,802

 
(7,086
)
 
32,394

Other income (expense)
(92,319
)
 
(15
)
 
30

 

 
(92,304
)
Income (loss) before income taxes including non-controlling interests
$
(88,835
)
 
$
25,179

 
$
10,832

 
$
(7,086
)
 
$
(59,910
)
 
 
Nine months ended September 30, 2018:
 
Revenues from non-affiliates
$
1,328,994

 
$
93,663

 
$
46,344

 
$

 
$
1,469,001

Inter-segment revenues

 
119,095

 
114,898

 
(233,993
)
 

Total revenues
1,328,994

 
212,758

 
161,242

 
(233,993
)
 
1,469,001

Operating income (loss)
(53,159
)
 
101,457

 
25,415

 
(24,357
)
 
49,356

Other expense
(370,311
)
 
(703
)
 
(99
)
 

 
(371,113
)
Income (loss) before income taxes including non-controlling interests
$
(423,470
)
 
$
100,754

 
$
25,316

 
$
(24,357
)
 
$
(321,757
)
 
 
Nine months ended September 30, 2017:
 
Revenues from non-affiliates
$
761,450

 
$
48,939

 
$
33,566

 
$

 
$
843,955

Inter-segment revenues

 
76,674

 
68,028

 
(144,702
)
 

Total revenues
761,450

 
125,613

 
101,594

 
(144,702
)
 
843,955

Operating income (loss)
(12,972
)
 
69,059

 
9,161

 
(7,383
)
 
57,865

Other income (expense)
(59,027
)
 
(13
)
 
34

 

 
(59,006
)
Income (loss) before income taxes including non-controlling interests
$
(71,999
)
 
$
69,046

 
$
9,195

 
$
(7,383
)
 
$
(1,141
)