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 March 31, 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: 001-38212

Oasis Midstream Partners LP
(Exact name of registrant as specified in its charter)
 
 
 
 
Delaware
 
47-1208855
(State or other jurisdiction of
incorporation or organization)
 
(I.R.S. Employer
Identification No.)
 
 
1001 Fannin Street, Suite 1500
Houston, Texas
 
77002
(Address of principal executive offices)
 
(Zip Code)

(281) 404-9500
(Registrant’s telephone number, including area code)
 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes   ý No ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  ý   No  ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act. 

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Large accelerated filer
o
Accelerated filer
o
 
 
 
 
Non-accelerated filer
ý (Do not check if a smaller reporting company)
Smaller reporting company
o
 
 
 
 
 
 
Emerging growth company
ý
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.   ý
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ¨  No  ý
At April 30, 2018 , there were 27,523,966 units representing limited partner interests (consisting of 13,773,966 common units and 13,750,000 subordinated units) outstanding.
 
 
 
 
 


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Page



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PART I — FINANCIAL INFORMATION
Item 1. — Financial Statements (Unaudited)
OASIS MIDSTREAM PARTNERS LP
CONDENSED CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
 
 
 
March 31, 2018
 
December 31, 2017
 
(In thousands)
ASSETS
 
 
 
Current assets
 
 
 
  Cash and cash equivalents
$
4,048

 
$
883

  Accounts receivable
920

 
834

  Accounts receivable from Oasis Petroleum
57,144

 
85,818

  Prepaid expenses
747

 
778

Total current assets
62,859

 
88,313

Property, plant and equipment
743,578

 
653,928

Less: accumulated depreciation and amortization
(40,696
)
 
(34,348
)
Total property, plant and equipment, net
702,882

 
619,580

Other assets
1,899

 
2,013

Total assets
$
767,640

 
$
709,906

LIABILITIES AND EQUITY
 
 
 
Current liabilities
 
 
 
Accounts payable
$
593

 
$

Accounts payable to Oasis Petroleum
15,533

 
11,638

Accrued liabilities
67,239

 
58,818

Accrued interest payable
73

 
114

Total current liabilities
83,438

 
70,570

Long-term debt
117,000

 
78,000

Asset retirement obligations
1,332

 
1,316

Total liabilities
201,770

 
149,886

Commitments and contingencies (Note 9)

 

Partners’ Equity
 
 
 
Limited Partner
 
 
 
Common units (13,774 units outstanding at March 31, 2018)
166,943

 
167,401

Subordinated units (13,750 units outstanding at March 31, 2018)
78,657

 
79,173

General Partner

 

Total partners’ equity
245,600

 
246,574

Non-controlling interests
320,270

 
313,446

Total equity
565,870

 
560,020

Total liabilities and equity
$
767,640

 
$
709,906



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

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OASIS MIDSTREAM PARTNERS LP
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)
 
Three Months Ended March 31,
 
2018
 
2017
 
(In thousands, except per unit data)
Revenues
 
 
 
Midstream services for Oasis Petroleum
$
60,853

 
$
37,367

Midstream services for third parties
568

 
273

Total revenues
61,421

 
37,640

Operating expenses
 
 
 
Direct operating
17,116

 
9,023

Depreciation and amortization
6,364

 
3,458

General and administrative
6,150

 
4,396

Total operating expenses
29,630

 
16,877

Operating income
31,791

 
20,763

Other income (expense)
 
 
 
Interest expense, net of capitalized interest
(262
)
 
(1,217
)
Other income (expense)

 
(2
)
Total other income (expense)
(262
)
 
(1,219
)
Income before income taxes
31,529

 
19,544

Income tax expense

 
(7,295
)
Net income
31,529

 
$
12,249

Less: Net income attributable to non-controlling interests
21,575

 
 
Net income attributable to Oasis Midstream Partners LP
$
9,954

 
 
Earnings per limited partner unit — Basic and Diluted
 
 
 
Common units (Note 12)
$
0.36

 
 
Subordinated units (Note 12)
0.36

 
 
Weighted average number of limited partner units outstanding — Basic
 
 
 
Common units (Note 12)
13,750

 
 
Subordinated units (Note 12)
13,750

 
 
Weighted average number of limited partner units outstanding — Diluted
 
 
 
Common units (Note 12)
13,754

 
 
Subordinated units (Note 12)
13,750

 
 
Cash distributions declared per limited partner unit
 
 
 
Common units
$
0.3925

 
 
Subordinated units
0.3925

 
 





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

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OASIS MIDSTREAM PARTNERS LP
CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
(UNAUDITED)
 
Partnership
 
 
 
 
 
Common Units
 
Subordinated Units
 
Non-controlling Interests
 
Total
 
(In thousands)
Balance as of December 31, 2017
$
167,401

 
$
79,173

 
$
313,446

 
$
560,020

Contributions from non-controlling interests

 

 
23,565

 
23,565

Distributions to non-controlling interests

 

 
(38,316
)
 
(38,316
)
Distributions to unitholders
(5,498
)
 
(5,493
)
 

 
(10,991
)
Equity-based compensation
63

 

 

 
63

Net income
4,977

 
4,977

 
21,575

 
31,529

Balance as of March 31, 2018
$
166,943

 
$
78,657

 
$
320,270

 
$
565,870






















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

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OASIS MIDSTREAM PARTNERS LP
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
 
Three Months Ended March 31,
 
2018
 
2017
 
(In thousands)
Cash flows from operating activities:
 
 
 
Net income
$
31,529

 
$
12,249

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
Depreciation and amortization
6,364

 
3,458

Deferred income taxes

 
1,937

Equity-based compensation expenses
63

 
348

Deferred financing costs amortization and other
114

 

Working capital changes:
 
 
 
      Change in accounts and insurance receivable
28,588

 
(1,407
)
      Change in prepaid expenses
31

 
190

      Change in accounts payable and accrued liabilities
8,062

 
(1,754
)
      Change in current income taxes payable

 
5,358

Net cash provided by operating activities
74,751

 
20,379

Cash flows from investing activities:
 
 
 
      Capital expenditures
(76,440
)
 
(23,814
)
Net cash used in investing activities
(76,440
)
 
(23,814
)
Cash flows from financing activities:
 
 
 
Capital contributions from parent

 
3,435

Capital contributions from non-controlling interests
15,161

 

Distributions to non-controlling interests
(38,316
)
 

Distributions to unitholders
(10,991
)
 

Proceeds from revolving credit facility
57,000

 

Principal payments on revolving credit facility
(18,000
)
 

Net cash provided by financing activities
4,854

 
3,435

Increase in cash and cash equivalents
3,165

 

Cash:
 
 
 
Beginning of period
883

 

End of period
$
4,048

 
$

Supplemental non-cash transactions:
 
 
 
Change in accrued capital expenditures
$
4,806

 
$
(10,633
)
Change in asset retirement obligations
16

 
56

Contribution of capital expenditures from non-controlling interests
8,404

 







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

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OASIS MIDSTREAM PARTNERS LP
Notes to Condensed Consolidated Financial Statements (Unaudited)
1. Organization and Nature of Operations
Organization. Oasis Midstream Partners LP (the “Partnership” or “Oasis Midstream”) is a growth-oriented, fee-based master limited partnership formed by its sponsor, Oasis Petroleum Inc. (together with its subsidiaries, “Oasis Petroleum”) to own, develop, operate and acquire a diversified portfolio of midstream assets in North America that are integral to the oil and natural gas operations of Oasis Petroleum and are strategically positioned to capture volumes from other producers.
Contributed businesses. The Partnership conducts its business through its ownership of development companies: Bighorn DevCo LLC (“Bighorn DevCo”), Bobcat DevCo LLC (“Bobcat DevCo”) and Beartooth DevCo LLC (“Beartooth DevCo,” and collectively with Bighorn DevCo and Bobcat DevCo, the “DevCos”). In connection with the Partnership’s initial public offering on September 25, 2017 , Oasis Petroleum contributed to the Partnership ownership interests in the following DevCos:
DevCos
 
Areas Served
 
Service Lines
 
Oasis Midstream Ownership
Bighorn DevCo
 
Wild Basin
 
Gas processing
Crude stabilization
Crude blending
Crude storage
Crude transportation
 
100%
Bobcat DevCo
 
Wild Basin
 
Gas gathering
Gas compression
Gas lift
Crude gathering
Produced and flowback water gathering
Produced and flowback water disposal
 
10%
Beartooth DevCo
 
Alger
Cottonwood
Hebron
Indian Hills
Red Bank
Wild Basin
 
Produced and flowback water gathering
Produced and flowback water disposal
Freshwater supply and distribution
 
40%
In exchange for the contribution of ownership interests in the DevCos, Oasis Petroleum received 5,125,000  common units and 13,750,000  subordinated units, representing a limited partner interest in the Partnership and the right to receive cash distributions from the Partnership. In addition to and concurrent with the closing of the initial public offering, the Partnership’s general partner, OMP GP LLC (the “General Partner”), retained a non-economic general partnership interest and was issued incentive distribution rights in the Partnership (the “IDRs”).
Nature of business. The Partnership operates in two primary areas with developed midstream infrastructure, both of which are supported by significant acreage dedications from Oasis Petroleum. In Wild Basin, Oasis Petroleum has dedicated to the Partnership approximately 65,000 acres, of which approximately 29,000 acres are within Oasis Petroleum’s current gross operated acreage position, and in which the Partnership has the right to provide oil, gas and produced and flowback water services to support Oasis Petroleum’s existing and future production. Outside of Wild Basin, Oasis Petroleum has dedicated to the Partnership approximately 581,000 acres for produced and flowback water services, of which approximately 299,000 acres are within Oasis Petroleum’s current gross operated acreage, and approximately 364,000 acres are for freshwater services, of which approximately 203,000 acres are within Oasis Petroleum’s current gross operated acreage.
The Partnership generates a substantial portion of its revenues through long-term, fee-based contractual arrangements with wholly owned subsidiaries of Oasis Petroleum for midstream services. These services include (i) gas gathering, compression, processing and gas lift services; (ii) crude gathering, stabilization, blending, storage and transportation services; (iii) produced and flowback water gathering and disposal services; and (iv) freshwater supply and distribution services. The revenue earned from these services is generally directly related to the volume of natural gas, crude oil and water that flows through Oasis Midstream’s systems, and Oasis Midstream generally does not take ownership of the crude oil or natural gas that it handles for its customers, including Oasis Petroleum.
Predecessor . Prior to September 25, 2017, Oasis Petroleum’s midstream services were performed by Oasis Midstream Services LLC (“OMS”), which constitutes the predecessor to the Partnership for accounting purposes (the “Predecessor”). The condensed consolidated financial statements include the results of the Predecessor for the periods presented prior to the initial public offering on September 25, 2017. Certain midstream infrastructure assets, liabilities, revenues and expenses included in the Predecessor’s historical financial statements have been excluded from the businesses of the DevCos upon formation. These

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excluded assets are not included in the condensed consolidated financial statements for the periods presented subsequent to the initial public offering on September 25, 2017. Substantially all of the services of the Predecessor were provided to Oasis Petroleum North America LLC (“OPNA”), a wholly owned subsidiary of Oasis Petroleum that conducts Oasis Petroleum’s oil and natural gas exploration and production (“E&P”) activities in the Williston Basin. The Predecessor financial statements have been prepared from the separate records maintained by Oasis Petroleum and may not necessarily be indicative of the actual results of operations that might have occurred if the Predecessor had been operated separately during the periods reported.
2 . Basis of Presentation
Presentation
The accompanying condensed consolidated financial statements of the Partnership have not been audited by the Partnership’s independent registered public accounting firm, except that the Condensed Consolidated Balance Sheet at December 31, 2017 is derived from audited financial statements. In the opinion of management, all adjustments, consisting of normal recurring adjustments necessary for fair statement of the Partnership’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 Partnership’s audited consolidated financial statements and notes thereto included in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2017 (“ 2017 Annual Report”).
Consolidation
The Partnership’s condensed consolidated financial statements include its accounts and the accounts of the DevCos. With respect to Bobcat DevCo and Beartooth DevCo, management has determined that OMS’s equity at risk was established with non-substantive voting rights, making Bobcat DevCo and Beartooth DevCo variable interest entities (“VIEs”) under the rules of the Financial Accounting Standards Board (“FASB”). Through its 100% ownership interest in OMP Operating LLC (“OMP Operating”), which owns controlling interests in Bobcat DevCo and Beartooth DevCo, the Partnership has the authority to direct the activities that most significantly affect the economic performance of these entities and the obligation to absorb losses or the right to receive benefits that could be potentially significant to them. Therefore, the Partnership is considered the primary beneficiary of Bobcat DevCo and Beartooth DevCo and is required to consolidate these entities in its financial statements under the VIE consolidation model. With respect to Bighorn DevCo, the Partnership is required to consolidate Bighorn DevCo under the voting interest consolidation model because Bighorn DevCo is an indirect wholly owned subsidiary of the Partnership.
Non-Controlling Interests
The non-controlling interests represent Oasis Petroleum’s retained ownership interest in Bobcat DevCo and Beartooth DevCo of 90% and 60% , respectively.
Significant Accounting Policies
There have been no material changes to the Partnership’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 Partnership adopted Accounting Standards Update No. 2014-09, R evenue from Contracts with Customers  (“ASU 2014-09”), which uses 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 Partnership’s financial position, cash flows or results of operations. Disclosures in accordance with the requirements of ASU 2014-09 have been provided in Note 3 .
Statement of cash flows. In the first quarter of 2018 , the Partnership 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 retrospective basis. The adoption of ASU 2016-15 did not result in a material impact to the Partnership’s financial position, cash flows, results of operations or financial statement disclosures.
Business combinations. In the first quarter of 2018 , the Partnership 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 was adopted

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on a prospective basis. The adoption of ASU 2017-01 did not result in a material impact to the Partnership’s financial position, cash flows, results of operations or financial statement disclosures.
Equity-based compensation. In the first quarter of 2018 , the Partnership 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 adopted on a prospective basis. The adoption of ASU 2017-09 did not result in a material impact to the Partnership’s financial position, cash flows, results of operations or financial statement disclosures.
Recent Accounting Pronouncements
Leases. In February 2016, the FASB issued Accounting Standards Update No. 2016-02,  Leases  (“ASU 2016-02”), which requires a lessee to recognize lease payment obligations and a corresponding right-of-use asset to be measured at fair value on the balance sheet. ASU 2016-02 also requires certain qualitative and quantitative disclosures about the amount, timing and uncertainty of cash flows arising from leases. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, including interim periods within those years. Also, in January 2018, the FASB issued Accounting Standards Update No. 2018-01,  Land easement practical expedient for transition to Topic 842  (“ASU 2018-01”), 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 Partnership plans to elect this practical expedient and is currently evaluating the effect that adopting this new lease guidance will have on its financial position, cash flows and results of operations.
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 Partnership adopted the new standard using the modified retrospective method. The Partnership 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 Partnership 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 Partnership’s financial position, cash flows or results of operations.
Revenue from contracts with customers
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.
Crude oil and natural gas revenues. The Partnership 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 Partnership has a series of performance obligations to provide daily integrated midstream services on a stand ready basis over a period of time. This represents a single performance obligation since the customer simultaneously receives and consumes the benefits of these services on a daily basis. Satisfaction of the 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 are due from customers 30 days after receipt of invoice.
Water revenues. The Partnership is also party to certain contracts with customers for water services, which includes produced and flowback water gathering and disposal services and freshwater supply and distribution services. Under its customer contracts for produced and flowback water services, the Partnership has a series of performance obligations to provide daily integrated midstream services on a stand ready basis over a period of time. This represents a single performance obligation since the customer simultaneously receives and consumes the benefits of these services on a daily basis. Satisfaction of the 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 are due from customers 30 days after receipt of invoice.

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Under its customer contracts for freshwater supply and distribution services, the Partnership supplies and distributes freshwater to its customers for hydraulic fracturing and production optimization. These contracts contain multiple distinct performance obligations since each freshwater barrel can be sold separately and is not dependent or highly interrelated with other barrels. Revenue associated with freshwater supply and 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.
Disaggregation of revenues
Revenues associated with contracts with customers for crude oil and natural gas and water services were as follows for the three months ended March 31, 2018 and 2017 :
 
Three Months Ended March 31,
 
2018
 
2017
 
(In thousands)
Crude oil and natural gas services revenue
$
31,413

 
$
17,411

Water services revenue
30,008

 
19,956

Total revenues
$
61,421

 
$
37,640

Contract balances
Under the Partnership’s customer contracts, invoicing occurs once the Partnership’s performance obligations have been satisfied, at which point payment is unconditional. Accordingly, the Partnership’s contracts do not give rise to contract assets or liabilities under ASC 606.
Performance obligations
The majority of the Partnership’s customer contracts have a term greater than one-year. The Partnership recognizes revenue under the right to invoice practical expedient for its contracts for crude oil, natural gas and produced and flowback water services and is not required to disclose the transaction price allocated to remaining performance obligations. Under the Partnership’s customer contracts for freshwater supply and distribution services, each barrel of freshwater delivered represents a separate performance obligation; therefore, future volumes delivered are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.
4. Transactions with Affiliates
Revenues. The Partnership generates a substantial portion of its revenues through 15 -year, fee-based contractual arrangements with wholly owned subsidiaries of Oasis Petroleum for midstream services. These services include (i) gas gathering, compression, processing and gas lift services; (ii) crude gathering, stabilization, blending, storage and transportation services; (iii) produced and flowback water gathering and disposal services; and (iv) freshwater supply and distribution services. The revenue earned from these services is generally directly related to the volume of natural gas, crude oil and produced and flowback water that flows through the Partnership’s systems, and the Partnership generally does not take ownership of the crude oil or natural gas that it handles for its customers, including Oasis Petroleum.
Expenses. Oasis Petroleum provides substantial labor and overhead support for the Partnership. The Partnership is party to a 15 -year services and secondment agreement with Oasis Petroleum pursuant to which Oasis Petroleum provides all personnel, equipment, electricity, chemicals and services (including third-party services) required for the Partnership to operate such assets, and the Partnership reimburses Oasis Petroleum for its share of the actual costs of operating such assets (the “Services and Secondment Agreement”). In addition, pursuant to the Services and Secondment Agreement, Oasis Petroleum performs centralized corporate, general and administrative services for the Partnership, such as legal, corporate recordkeeping, planning, budgeting, regulatory, accounting, billing, business development, treasury, insurance administration and claims processing, risk management, health, safety and environmental, information technology, human resources, investor relations, cash management and banking, payroll, internal audit, taxes and engineering. Oasis Petroleum has also seconded to the Partnership certain of its employees to operate, construct, manage and maintain its assets, and the Partnership reimburses Oasis Petroleum for direct general and administrative expenses incurred by Oasis Petroleum for the provision of these services. The expenses of executive officers and non-executive employees are allocated to the Partnership based on the amount of time spent managing its business and operations. For the periods prior to the initial public offering, shared services and direct labor were allocated to the Predecessor primarily based on headcount and direct usage during the respective years. Management believes that these allocations are reasonable and reflect the utilization of services provided and benefits received, but may differ from the cost that

8


would have been incurred had the Predecessor operated as a stand-alone company for the periods presented prior to the initial public offering.
Additionally, for the three months ended March 31, 2017 , interest expense was recognized by the Predecessor related to its funding activity with Oasis Petroleum based on capital expenditures for the period using the weighted average effective interest rate for Oasis Petroleum’s long-term indebtedness.
General and administrative expenses and interest expense incurred from affiliate transactions with Oasis Petroleum include the following for the periods presented:
 
Three Months Ended March 31,
 
2018
 
2017
 
(In thousands)
Expenses from affiliates
 
 
 
General and administrative
$
5,472

 
$
2,704

Interest expense, net of capitalized interest

 
1,217

5. Accrued Liabilities
The following table sets forth the Partnership’s accrued liabilities for the periods presented:
 
March 31, 2018
 
December 31, 2017
 
(In thousands)
Accrued capital costs
$
52,635

 
$
47,843

Accrued operating expenses
14,124

 
10,860

Other accrued liabilities
480

 
115

Total accrued liabilities
$
67,239

 
$
58,818

6. Property, Plant and Equipment
The following table sets forth the Partnership’s property, plant and equipment for the periods presented:
 
March 31, 2018
 
December 31, 2017
 
(In thousands)
Pipelines
$
291,016

 
$
255,231

Natural gas processing plant
112,090

 
102,371

Produced and flowback water facilities
80,806

 
80,050

Compressor stations
61,469

 
59,293

Other property and equipment
33,608

 
32,340

Construction in progress
164,589

 
124,643

Total property, plant and equipment
743,578

 
653,928

Less: accumulated depreciation and amortization
(40,696
)
 
(34,348
)
Total property, plant and equipment, net
$
702,882

 
$
619,580

7 . Long-Term Debt
On September 25, 2017, the Partnership entered into a credit agreement (the “Credit Agreement”) for a  $200.0 million  revolving credit facility with OMP Operating as borrower (the “Revolving Credit Facility”), which has a maturity date of September 25, 2022 . The Revolving Credit Facility is available to fund working capital and to finance acquisitions and other capital expenditures of the Partnership. The Revolving 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 Revolving Credit Facility may be increased up to  $400.0 million , subject to certain conditions. All obligations of OMP Operating, as the borrower under the Revolving Credit Facility, are unconditionally guaranteed on a joint and several basis by the Partnership, OMP Operating and Bighorn DevCo. At  March 31, 2018 $117.0 million  of borrowings were outstanding under the Revolving Credit Facility, and the weighted average interest rate on borrowings under the Revolving Credit Facility was 3.6% .

9


The Revolving Credit Facility is collateralized by mortgages and other security interests on substantially all of the Partnership’s and its subsidiaries’ properties and assets, including the equity interests in all present and future subsidiaries (subject to certain exceptions). Some or all of the collateral owned by Bobcat DevCo and Beartooth DevCo is subject to an intercreditor agreement between Wells Fargo, National Association (“Wells Fargo”), as administrative agent for the Revolving Credit Facility, and Wells Fargo as the administrative agent for the revolving credit facility of Oasis Petroleum, and acknowledged by OMS, Bobcat DevCo and Beartooth DevCo. The Revolving Credit Facility provides for customary representations, warranties and covenants, including, among other things, covenants relating to financial and collateral reporting, notices of material events, maintenance of the existence of the business and its properties, payment of obligations, the Partnership’s ability to enter into certain hedging agreements, limitations on the Partnership’s ability to sell or acquire properties and limitations on indebtedness and liens, dividends and distributions, transactions with affiliates and certain fundamental transactions.
Borrowings under the Revolving 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 Credit Agreement) 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 Credit Agreement). The applicable margin for borrowings under the Revolving Credit Facility is determined in accordance with the Credit Agreement as follows:
Consolidated Total Leverage Ratio
Applicable Margin
for Eurodollar Loans
 
Applicable Margin
for ABR Loans
 
Commitment Fee Rate
Less than or equal to 3.00 to 1.00
1.75
%
 
0.75
%
 
0.375
%
Greater than 3.00 to 1.00 but less than or equal to 3.50 to 1.00
2.00
%
 
1.00
%
 
0.375
%
Greater than 3.50 to 1.00 but less than or equal to 4.00 to 1.00
2.25
%
 
1.25
%
 
0.500
%
Greater than 4.00 to 1.00 but less than or equal to 4.50 to 1.00
2.50
%
 
1.50
%
 
0.500
%
Greater than 4.50 to 1.00
2.75
%
 
1.75
%
 
0.500
%
The Revolving Credit Facility also requires the Partnership to maintain the following financial covenants as of the end of each fiscal quarter:
Consolidated Total Leverage Ratio : Prior to the date on which one or more of the credit parties have issued an aggregate principal amount of at least $150.0 million of senior notes (as permitted under the Revolving Credit Facility) (such date the “Covenant Changeover Date”), the Partnership and OMP Operating’s ratio of Total Debt to EBITDA (each as defined in the Credit Agreement) on a quarterly basis may not exceed 4.50 to 1.00 (or during an Acquisition Period (as defined in the Credit Agreement), 5.00 to 1.00 ). On a quarterly basis following the Covenant Changeover Date, the Partnership and OMP Operating’s ratio of Total Debt to EBITDA may not exceed 5.25 to 1.00 .
Consolidated Senior Secured Leverage Ratio : On a quarterly basis following the Covenant Changeover Date, the Partnership and OMP Operating’s ratio of Consolidated Senior Secured Funded Debt to EBITDA (each as defined in the Credit Agreement) may not exceed 3.75 to 1.00 .
Consolidated Interest Coverage Ratio : On a quarterly basis prior to the Covenant Changeover Date, the Partnership and OMP Operating’s ratio of EBITDA to Consolidated Interest Expense (each as defined in the Credit Agreement) may not be less than 3.00 to 1.00 and on a quarterly basis following the Covenant Changeover Date, the Partnership and OMP Operating’s ratio of EBITDA to Consolidated Interest Expense may not be less than 2.50 to 1.00 .
The Partnership was in compliance with the financial covenants of the Revolving Credit Facility at March 31, 2018 .
8. Income Taxes
The Partnership is not a taxable entity for U.S. federal income tax purposes, and taxes are generally borne by unitholders through the allocation of taxable income. Accordingly, for the periods subsequent to the initial public offering, the Partnership does not record deferred taxes related to the aggregate differences in the tax bases and reported amounts of its assets and liabilities.
The Partnership did not record a tax provision for the  three months ended March 31, 2018 . The provision for income taxes recorded by the Predecessor for the three months ended March 31, 2017 was determined as if the Predecessor was a stand-alone taxpayer for the period prior to the initial public offering on September 25, 2017 . The Predecessor’s effective tax rate for the three months ended March 31, 2017 was 37.3% . This effective tax rate was consistent with the statutory tax rate applicable to the U.S. and the blended state rate for the states in which the Predecessor conducted business.
9 . Commitments and Contingencies

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The Partnership has various contractual obligations in the normal course of its operations. Currently, there are no unrecorded commitments in the accompanying Condensed Consolidated Balance Sheets as of March 31, 2018 .
Litigation. The Partnership is party to various legal and/or regulatory proceedings from time to time arising in the ordinary course of business. When the Partnership determines that a loss is probable of occurring and is reasonably estimable, the Partnership accrues an undiscounted liability for such contingencies based on its best estimate using information available at the time. The Partnership discloses contingencies where an adverse outcome may be material, or where in the judgment of management, the matter should otherwise be disclosed.
Mirada litigation . On March 23, 2017, Mirada filed a lawsuit against Oasis Petroleum, OPNA, and OMS, seeking monetary damages in excess of $100.0 million , declaratory relief, attorneys’ fees and costs (Mirada Energy, LLC, et al. v. Oasis Petroleum North America LLC, et al.; in the 334th Judicial District Court of Harris County, Texas; Case Number 2017-19911). In its original lawsuit, Mirada asserts that it is a working interest owner in certain acreage owned and operated by Oasis Petroleum in Wild Basin. Specifically, Mirada asserts that Oasis Petroleum has breached certain agreements by: (1) failing to allow Mirada to participate in Oasis Petroleum’s midstream operations in Wild Basin; (2) refusing to provide Mirada with information that Mirada contends is required under certain agreements and failing to provide information in a timely fashion; (3) failing to consult with Mirada and failing to obtain Mirada’s consent prior to drilling more than one well at a time in Wild Basin; and (4) by overstating the estimated costs of proposed well operations in Wild Basin. Mirada seeks a declaratory judgment that OPNA be removed as operator in Wild Basin at Mirada’s election and that Mirada be allowed to elect a new operator; that certain agreements apply to Oasis Petroleum and Mirada and Wild Basin with respect to this dispute; that Oasis Petroleum be required to provide all information within its possession regarding proposed or ongoing operations in Wild Basin; and that OPNA not be permitted to drill, or propose to drill, more than one well at a time in Wild Basin without obtaining Mirada’s consent. Mirada also seeks a declaratory judgment with respect to Oasis Petroleum’s current midstream operations in Wild Basin. Specifically, Mirada seeks a declaratory judgment that Mirada has a right to participate in Oasis Petroleum’s Wild Basin midstream operations, consisting of produced and flowback water disposal, crude oil gathering and gas gathering and processing; that, upon Mirada’s election to participate, Mirada is obligated to pay its proportionate costs of Oasis Petroleum’s midstream operations in Wild Basin; and that Mirada would then be entitled to receive a share of revenues from the midstream operations and would not be charged any amount for its use of these facilities for production from the “Contract Area.”
On June 30, 2017, Mirada amended its original petition to add a claim that Oasis Petroleum has breached certain agreements by charging Mirada for midstream services provided by its affiliates and to seek a declaratory judgment that Mirada is entitled to be paid its share of total proceeds from the sale of hydrocarbons received by OPNA or any affiliate of OPNA without deductions for midstream services provided by OPNA or its affiliates.
On February 2, 2018 and February 16, 2018, Mirada filed a second and third amended petition, respectively. In these filings, Mirada alleges new legal theories for being entitled to enforce the underlying contracts, and added Bighorn DevCo LLC, Bobcat DevCo LLC and Beartooth DevCo LLC as defendants, asserting that these entities were created in bad faith in an effort to avoid contractual obligations owed to Mirada. Mirada may further amend its petition from time to time to assert additional claims as well as defendants.
Oasis Petroleum believes that Mirada’s claims are without merit, that Oasis Petroleum has complied with its obligations under the applicable agreements and that some of Mirada’s claims are grounded in agreements which do not apply to Oasis Petroleum. Oasis Petroleum filed an answer denying all of Mirada’s claims and intends and continues to vigorously defend against Mirada’s claims and, to the extent we are made a party to the suit, we intend to vigorously defend ourselves against such claims. Discovery is ongoing, and each of the parties has made a number of procedural filings and motions, and additional filings and motions can be expected over the course of the claim. Trial is currently scheduled for May 2019. However, neither the Partnership nor Oasis Petroleum can predict or guarantee the ultimate outcome or resolution of such matter. If such matter were to be determined adversely to the Partnership’s or Oasis Petroleum’s interests, or if the Partnership or Oasis Petroleum were forced to settle such matter for a significant amount, such resolution or settlement could have a material adverse effect on the Partnership’s business, results of operations and financial condition. Such an adverse determination could materially impact Oasis Petroleum’s ability to operate its properties in Wild Basin or develop its identified drilling locations in Wild Basin on its current development schedule. A determination that Mirada has a right to participate in Oasis Petroleum’s midstream operations could materially reduce the interests of Oasis Petroleum and the Partnership in its current assets and future midstream opportunities and related revenues in Wild Basin. Under the Omnibus Agreement the Partnership entered into with Oasis Petroleum in connection with the closing of the initial public offering, Oasis Petroleum agreed to indemnify the Partnership for any losses resulting from this litigation. However, the Partnership cannot guarantee that such indemnity will fully protect the Partnership from the adverse consequences of any adverse ruling.
10. Equity-Based Compensation
The Oasis Midstream Partners LP 2017 Long Term Incentive Plan (“LTIP”) provides for the grant, at the discretion of the Board of Directors of the General Partner, of options, unit appreciation rights, restricted units, phantom units, and other unit or

11


cash-based awards. The purpose of awards under the LTIP is to provide additional incentive compensation to individuals providing services to the Partnership, and to align the economic interests of such individuals with the interests of the Partnership’s unitholders.
As of March 31, 2018 , the aggregate number of common units that may be issued pursuant to any and all awards under the LTIP is equal to 1,980,118 common units, subject to adjustment due to recapitalization or reorganization, or related to forfeitures or expiration of awards, as provided under the LTIP. On January 1 of each calendar year following the adoption and prior to the expiration of the LTIP, the total number of common units that may be issued pursuant to the LTIP automatically increases by a number of common units equal to one percent of the number of common units outstanding on a fully diluted basis as of the close of business on the immediately preceding December 31 (calculated by adding to the number of common units outstanding, all outstanding securities convertible into common units on such date on an as converted basis). As a result of this adjustment, an additional 137,618 common units were reserved for issuance pursuant to awards under the LTIP on January 1, 2018 .
Phantom unit awards.  On October 19, 2017 , the Partnership granted under its LTIP  101,500  phantom unit awards (collectively the “Phantom Units” and each a “Phantom Unit”) to certain employees of Oasis Petroleum who are non-employees of the Partnership. Each Phantom Unit represents the right to receive a cash payment equal to the fair market value of one common unit on the day prior to the date it vests. Award recipients are also entitled to Distribution Equivalent Rights (a “DER”), which represent the right to receive a cash payment equal to the value of the distributions paid on one common unit between the grant date and the vesting date. The Phantom Units vest in equal amounts each year over a  three -year period. The Phantom Units are accounted for as liability-classified awards since the awards will settle in cash. 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. Oasis Petroleum will reimburse the Partnership for the cash settlement amount of these awards. The Partnership recognizes in its Condensed Consolidated Balance Sheets the compensation cost associated with these awards in accounts receivable from Oasis Petroleum and accrued liabilities. As of  March 31, 2018 , unrecognized compensation cost for all outstanding Phantom Units was  $1.5 million , which is expected to be recognized over a weighted average period of  2.66  years. The following table summarizes information related to the Phantom Units held by certain non-employees of the Partnership:
 
 
Phantom Units
Outstanding at beginning of period
 
99,100

Granted
 

Vested
 

Forfeited
 
(2,350
)
Outstanding at end of period
 
96,750

Restricted unit awards.  The Partnership has granted to certain directors restricted unit awards under its LTIP, which vest over a  one -year period. These awards are accounted for as equity-classified awards since the awards will settle in common units upon vesting. 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. During the three months ended March 31, 2018 , the Partnership granted to certain directors 12,200 common units which vest over a one-year period with a weighted-average grant date fair value of $16.50 per common unit. Compensation cost associated with these awards was approximately  $0.1 million  for the  three months ended  March 31, 2018  and is included in general and administrative expenses on the Condensed Consolidated Statements of Operations. As of  March 31, 2018 , unrecognized compensation cost for all outstanding restricted unit awards was  $0.3 million , which is expected to be recognized over a weighted average period of  0.7 years. The following table summarizes information related to restricted units held by certain directors of the Partnership:
 
 
Restricted Units
Outstanding at beginning of period
 
11,766

Granted
 
12,200

Vested
 

Forfeited
 

Outstanding at end of period
 
23,966

Restricted stock awards (Predecessor).  Prior to the initial public offering on September 25, 2017 , certain employees of Oasis Petroleum were granted restricted stock awards under its Amended and Restated 2010 Long Term Incentive Plan, the majority

12


of which vest over a  three -year period. Oasis Petroleum accounts for these awards as equity-classified awards, in accordance with GAAP. The value of restricted stock grants is based on the closing sales price of Oasis Petroleum’s common stock on the date of grant, and compensation expense is recognized ratably over the requisite service period. During the three months ended March 31, 2017 , employees of the Predecessor were granted restricted stock awards equal to 91,300 shares of common stock with a $15.19 weighted average grant date fair value per share.
In accordance with its indirect shared service expense allocation from Oasis Petroleum, the Predecessor recorded equity-based compensation expense associated with these awards of approximately  $0.3 million for the  three months ended March 31, 2017 in general and administrative expenses on the Condensed Consolidated Statements of Operations. There is no unrecognized expense associated with these awards for the Partnership.
11. Partnership Equity and Distributions
Minimum quarterly distribution. The partnership agreement requires that all of the Partnership’s available cash be distributed quarterly. Under the current cash distribution policy, the Partnership intends to distribute to the holders of common units and subordinated units on a quarterly basis at least the minimum quarterly distribution of $0.3750 per unit, or $1.50 on an annualized basis, to the extent the Partnership has sufficient cash after establishment of cash reserves and payment of fees and expenses, including payments to the General Partner and its affiliates. 
On February 26, 2018 , the Partnership paid the initial quarterly cash distribution to its unitholders of $0.0245 per unit related to the six days ended September 30, 2017 and $0.3750 per unit related to the three months ended December 31, 2017 . The third quarter 2017 distribution was prorated from the closing of the Partnership’s initial public offering on September 25, 2017 .
On  May 7, 2018 , the Board of Directors of the General Partner, declared the quarterly cash distribution for the first quarter of 2018 of  $0.3925  per unit. The distribution will be payable on  May 29, 2018  to unitholders of record as of  May 17, 2018 .
Subordinated units.  Oasis Petroleum owns all of the Partnership’s subordinated units. The partnership agreement provides that, during the subordination period, the common units have the right to receive distributions of available cash from operating surplus each quarter in an amount equal to the minimum quarterly distribution, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. No arrearages will accrue or be payable on the subordinated units.
When the subordination period ends, each outstanding subordinated unit will convert into one common unit and will thereafter participate pro rata with the other common units in distributions of available cash.
The subordination period will end on December 31, 2020 if each of the following tests are met:
for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date, aggregate distributions from operating surplus equaled or exceeded the sum of the minimum quarterly distribution multiplied by the total number of common units and subordinated units outstanding in each quarter in each period;
for the same three consecutive, non-overlapping four-quarter periods, the “adjusted operating surplus” (as defined in the partnership agreement) equaled or exceeded the sum of the minimum quarterly distribution multiplied by the total number of common units and subordinated units outstanding during each quarter on a fully diluted weighted average basis; and
there are no arrearages in payment of the minimum quarterly distribution on the common units.
Notwithstanding the foregoing, the subordination period will automatically terminate, and all of the subordinated units will convert into common units on a one-for-one basis, on the first business day after the distribution to unitholders in respect of any quarter, beginning with the quarter ending December 31, 2018, if each of the following has occurred:
for one four-quarter period immediately preceding that date, aggregate distributions from operating surplus exceeded 150.0% of the minimum quarterly distribution multiplied by the total number of common units and subordinated units outstanding in each quarter in the period;
for the same four-quarter period, the “adjusted operating surplus” (as defined in the Partnership’s Amended and Restated Agreement of Limited Partnership) equaled or exceeded 150.0% of the sum of the minimum quarterly distribution multiplied by the total number of common units and subordinated units outstanding during each quarter on a fully diluted weighted average basis, plus the related distribution on the IDRs; and
there are no arrearages in payment of the minimum quarterly distributions on the common units.
Incentive distribution rights (“IDRs”). The General Partner owns all of the Partnership’s IDRs, which will entitle it to increasing percentages, up to a maximum of 50.0% , of the cash the Partnership distributes in excess of $0.43125  per unit per quarter. The maximum distribution of  50.0%  does not include any distributions that Oasis Petroleum may receive on common units or subordinated units that it owns.

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Percentage allocations of available cash from operating surplus.  For any quarter in which the Partnership has distributed cash from operating surplus to the common and subordinated unitholders in an amount equal to the minimum distribution, the Partnership will distribute any additional available cash from operating surplus for that quarter among the unitholders and the IDR holders in the following manner:
 
 
 
 
Marginal Percentage Interest in Distributions
 
 
Total Quarterly Distribution Per Unit
 
Unitholders
 
IDR Holders
Minimum Quarterly Distribution
 
up to $0.3750
 
100
%
 
%
First Target Distribution
 
above $0.3750 up to $0.4313
 
100
%
 
%
Second Target Distribution
 
above $0.4313 up to $0.4688
 
85
%
 
15
%
Third Target Distribution
 
above $0.4688 up to $0.5625
 
75
%
 
25
%
Thereafter
 
above $0.5625
 
50
%
 
50
%
12. Earnings Per Limited Partner Unit
Earnings per limited partner unit is computed by dividing the respective limited partners’ interest in earnings attributable to the Partnership by the weighted average number of common units and subordinated units outstanding. Because there is more than one class of participating securities, the Partnership uses the two-class method when calculating earnings per limited partner unit. The classes of participating securities include common units, subordinated units, and IDRs.
Diluted earnings per limited partner unit reflects the potential dilution that could occur if securities or agreements to issue common units, such as awards under the LTIP, were exercised, settled or converted into common units. When it is determined that potential common units should be included in diluted net income per limited partner unit calculation, the impact is reflected by applying the treasury stock method.
The following table presents the calculation of earnings per limited partner unit for common units and subordinated units:
 
 
Three Months Ended March 31,
 
 
2018
 
 
(in thousands, except per unit data)
Net income attributable to Oasis Midstream Partners LP
 
$
9,954

Less: Net income attributable to IDRs
 

Net income attributable to limited partners
 
$
9,954

 
 
 
Net income allocable to common units
 
$
4,977

Net income allocable to subordinated units
 
4,977

Net income attributable to limited partners
 
$
9,954

 
 
 
Net income attributable to limited partners per limited partner unit — Basic and Diluted
 
 
Common Units
 
$
0.36

Subordinated Units
 
0.36

 
 
 
Weighted average limited partner units outstanding — Basic
 
 
Common Units
 
13,750

Subordinated Units
 
13,750

 
 
 
Weighted average limited partner units outstanding — Diluted
 
 
Common Units
 
13,754

Subordinated Units
 
13,750

 
 
 
Anti-dilutive restricted units
 
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Item 2. — Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” contained in our Annual Report on Form 10-K for the year ended December 31, 2017 (“2017 Annual Report”), as well as the unaudited condensed consolidated financial statements and notes thereto included in this Quarterly Report on Form 10-Q.
This Quarterly Report on Form 10-Q includes the results of operations of OMS Services LLC (“OMS”), our predecessor for accounting purposes (“Predecessor”), for periods prior to September 25, 2017 , the date on which we completed the initial public offering. Our Predecessor financial statements include 100% of the operations of OMS, reflecting the historical ownership of these assets by Oasis Petroleum Inc. (“Oasis Petroleum”). Our future results of operations may not be comparable to our Predecessor’s historical results of operations. Please read “Items Affecting Comparability of Our Financial Condition and Results of Operations.”
Unless the context otherwise requires, references in this section to “we,” “us,” “our” or like terms, when used in reference to periods prior to September 25, 2017 , refer to the operations of our Predecessor. References to “we,” “us,” “our” or like terms when used in reference to the period since September 25, 2017 , or when used in the present tense or prospectively, refer to Oasis Midstream Partners LP and its subsidiaries (the “Partnership” or “OMP”).
CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS
This Quarterly Report on Form 10-Q contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). These forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond our control. Forward-looking statements give our current expectations, contain projections of results of operations or of financial condition or provide forecasts of future events. Words such as “may,” “assume,” “forecast,” “position,” “predict,” “strategy,” “expect,” “intend,” “plan,” “estimate,” “anticipate,” “believe,” “project,” “budget,” “potential,” “continue” and other similar expressions are used to identify forward-looking statements.
Forward-looking statements can be affected by the assumptions used or by known or unknown risks or uncertainties. Consequently, no forward-looking statements can be guaranteed. When considering these forward-looking statements, you should keep in mind the risk factors and other cautionary statements discussed below and detailed under Part II, Item 1A. “Risk Factors” in this Quarterly Report on Form 10-Q. Actual results may vary materially. Although forward-looking statements reflect our good faith beliefs at the time they are made, you are cautioned not to place undue reliance on any forward-looking statements. You should also understand that it is not possible to predict or identify all such factors and you should not consider the following list to be a complete statement of all potential risks and uncertainties. Factors that could cause our actual results to differ materially from the results contemplated by such forward-looking statements include:
an inability of Oasis Petroleum or our other future customers to meet their drilling and development plans on a timely basis or at all;
the execution of our business strategies;
the demand for and price of oil and natural gas, on an absolute basis and in comparison to the price of alternative and competing fuels;
the fees we charge, and the margins we realize, from our midstream services;
the cost of achieving organic growth in current and new markets;
our ability to make acquisitions of other midstream infrastructure assets or other assets that complement or diversify our operations;
our ability to make acquisitions of other assets on economically acceptable terms from Oasis Petroleum;
the lack of asset and geographic diversification;
the suspension, reduction or termination of our commercial agreements with Oasis Petroleum;
labor relations and government regulations;
competition and actions taken by third-party producers, operators, processors and transporters;
outcomes of litigation and regulatory investigations, proceedings or inquiries;
the demand for, and the costs of developing and conducting, our midstream infrastructure services;
general economic conditions, including the risk of a prolonged economic slowdown or decline, or the risk of delay in a recovery, which can affect the long-term demand for midstream services;
the price and availability of equity and debt financing;

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operating hazards, natural disasters, weather-related delays, casualty losses and other matters beyond our control;
potential effects arising from cyber threats, terrorist attacks and any consequential or other hostilities;
interruption of our operations due to social, civil or political events or unrest;
changes in environmental, safety and other laws and regulations;
the effects of accounting pronouncements issued periodically during the periods covered by forward-looking statements;
changes in our tax status;
uncertainty regarding our future operating results; and
certain factors discussed elsewhere in this Quarterly Report on Form 10-Q.
All forward-looking statements speak only as of the date of this Quarterly Report on Form 10-Q. We disclaim any obligation to update or revise these statements unless required by securities law. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this Quarterly Report on Form 10-Q are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved. Some of the key factors which could cause actual results to vary from our expectations include, but are not limited to, commodity price volatility, inflation, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in projecting future throughput volumes, cash flow and access to capital, the timing of development expenditures and the other risks described under Part II, Item 1A. “Risk Factors” in this Quarterly Report on Form 10-Q.
Overview
We are a growth-oriented, fee-based master limited partnership formed by our sponsor, Oasis Petroleum Inc. (NYSE: OAS) (“Oasis Petroleum”), to own, develop, operate and acquire a diversified portfolio of midstream assets in North America that are integral to the oil and natural gas operations of Oasis Petroleum and are strategically positioned to capture volumes from other producers. Our current midstream operations are performed exclusively within the Williston Basin, one of the most prolific crude oil producing basins in North America. We generate a substantial portion of our revenues through 15-year, fixed-fee contracts, effective as of January 1, 2018, pursuant to which we provide crude oil, natural gas and water midstream services for Oasis Petroleum. We expect to grow acquisitively through accretive, dropdown acquisitions, as well as organically as Oasis Petroleum continues to develop its acreage. Additionally, we expect to grow by offering our services to third parties and through acquisitions of midstream assets from third parties.
We operate in two primary areas with developed midstream infrastructure, both of which are supported by significant acreage dedications from Oasis Petroleum. In Wild Basin, Oasis Petroleum has dedicated to us approximately 65,000 acres, of which approximately 29,000 acres are within Oasis Petroleum’s current gross operated acreage position, and in which we have the right to provide oil, gas and water services to support Oasis Petroleum’s existing and future production. Outside of the Wild Basin, Oasis Petroleum has dedicated to us approximately 581,000 acres for produced and flowback water services, of which approximately 299,000 acres are within Oasis Petroleum’s current gross operated acreage, and approximately 364,000 acres for freshwater services, of which approximately 203,000 acres are within Oasis Petroleum’s current gross operated acreage.
We conduct our business through our ownership of development companies (“DevCos”), two of which are jointly-owned with Oasis Petroleum. We own a 100% , 10% and 40% equity interest in Bighorn DevCo LLC (“Bighorn DevCo”), Bobcat DevCo LLC (“Bobcat DevCo”) and Beartooth DevCo LLC (“Beartooth DevCo”), respectively. Oasis Petroleum owns a 90% and 60% non-controlling equity interest in Bobcat DevCo and Beartooth DevCo, respectively. In connection with our initial public offering and effective as of January 1, 2018, we entered into 15-year, fixed-fee contracts for natural gas services (gathering, compression, processing and gas lift), crude oil services (gathering, stabilization, blending and storage), produced and flowback water services (gathering and disposal) and freshwater services (fracwater and flushwater supply and distribution) with wholly owned subsidiaries of Oasis Petroleum. At the same time, we became a party to the long-term, FERC-regulated transportation services agreement governing the transportation of crude oil via pipeline from the Wild Basin area to Johnson’s Corner. We generate a substantial portion of our revenues through these contracts. We generally do not take ownership of the crude oil or natural gas that we handle for our customers, including Oasis Petroleum, which minimizes our direct exposure to commodity prices. We believe our contractual arrangements provide us with stable and predictable cash flows over the long-term. Oasis Petroleum has also granted us a right of first offer (“ROFO”), which converts into a right of first refusal (“ROFR”) from any successor upon a change of control of Oasis Petroleum, with respect to its retained interests in our DevCos and any other midstream assets that Oasis Petroleum or any Oasis Petroleum successor builds with respect to its current acreage and elects to sell in the future.

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Highlights:
We declared the quarterly cash distribution for the first quarter of 2018 of  $0.3925  per unit, a 4.7% increase over the fourth quarter of 2017, in line with the forecasted 20% annualized increase in cash distributions.
Net income was $31.5 million for the three months ended March 31, 2018 and net cash from operating activities was $74.8 million for the three months ended March 31, 2018 .
Adjusted EBITDA was $38.2 million for the three months ended March 31, 2018 and net Adjusted EBITDA to the Partnership was $13.7 million for the three months ended March 31, 2018 . See “Non-GAAP Financial Measures” below.
Distributable Cash Flow was $11.9 million for the three months ended March 31, 2018 , resulting in distribution coverage of 1.11x. See “Non-GAAP Financial Measures” below.
The following table summarizes the gross throughput volumes, operating income, depreciation and amortization and capital expenditures for our midstream services for the period presented.
 
 
Three Months Ended March 31,
 
 
2018
 
 
(In thousands, except throughput volumes)
Bighorn DevCo
 
 
Crude oil services volumes (Mbopd)
 
41.5

Natural gas services volumes (MMscfpd)
 
98.0

Operating income
 
$
5,014

Depreciation and amortization
 
2,533

Capital expenditures
 
42,185

Bobcat DevCo
 
 
Crude oil services volumes (Mbopd)
 
36.3

Natural gas services volumes (MMscfpd)
 
140.4

Water services volumes (Mbowpd)
 
43.0

Operating income
 
$
16,915

Depreciation and amortization
 
2,086

Capital expenditures
 
27,834

Beartooth DevCo
 
 
Water services volumes (Mbowpd)
 
108.4

Operating income
 
$
10,585

Depreciation and amortization
 
1,745

Capital expenditures
 
11,227

Oasis Midstream Partners LP
 
 
DevCo operating income
 
$
32,514

Public company expenses
 
723

OMP operating income
 
31,791

How We Evaluate Our Operations
We use a variety of financial and operating metrics to analyze our operating results and profitability. These metrics are significant factors in assessing our operating results and profitability and include: (i) throughput volumes, (ii) Adjusted EBITDA, (iii) Distributable Cash Flow, (iv) capital expenditures, (v) direct operating expenses and (vi) general and administrative expenses.
Throughput Volumes
The amount of revenue we generate primarily depends on the volumes of crude oil, natural gas and water for which we provide midstream services. By connecting new producing wells to our gathering systems and by increasing capacity on our systems, we are able to increase volumes. Additionally, by performing routine maintenance and monitoring of our infrastructure, we are able to minimize service interruptions on our gathering systems.

17


Under our commercial agreements with Oasis Petroleum and its wholly owned subsidiaries, we provide (i) gas gathering, compression, processing and gas lift services, with approximately 65,000 dedicated acres in the Wild Basin operating area and firm capacity for gas attributable to such acreage; (ii) crude gathering, stabilization, blending and storage services, with approximately 65,000 dedicated acres in the Wild Basin operating area and firm capacity for crude oil attributable to such acreage; (iii) produced and flowback water gathering and disposal services, with approximately 65,000 dedicated acres in the Wild Basin operating area and firm capacity for produced and flowback water attributable to such acreage; (iv) produced and flowback water gathering and disposal services, with approximately 581,000 dedicated acres that includes the Alger, Cottonwood, Hebron, Indian Hills and Red Bank operating areas; and (v) freshwater supply and distribution services, with approximately 364,000 dedicated acres that includes the Hebron, Indian Hills, Red Bank and Wild Basin operating areas. In addition, the FERC-regulated crude transportation services agreement that we became a party to in connection with the initial public offering has up to 75,000 barrels per day of operating capacity and firm capacity for committed shippers.
Throughput volumes are affected by changes in the supply of and demand for crude oil and natural gas in the markets served directly or indirectly by our assets. Because the production rate of a well declines over time, we must continually obtain new supplies of crude oil, natural gas and produced and flowback water to maintain or increase the throughput volumes on our midstream systems. Because freshwater supply and distribution services are largely dependent on well completion activities, our ability to provide freshwater supply and distribution services is contingent on our customers drilling and completing new wells in and around our freshwater infrastructure. Our customers’ willingness to engage in new development activity is determined by a number of factors, the most important of which are the prevailing and projected prices of crude oil and natural gas, the cost to drill, complete and operate a well, expected well performance, the availability and cost of capital and environmental and government regulations. We generally expect the level of development activity to positively correlate with long-term trends in commodity prices and similarly, production levels to positively correlate with development activity.
Our ability to maintain or increase existing throughput volumes and obtain new supplies of crude oil, natural gas and produced, flowback and freshwater are impacted by:
successful development activity by Oasis Petroleum on our dedicated acreage and our ability to fund the capital costs required to connect our infrastructure assets to new wells;
our ability to utilize the remaining uncommitted capacity on, or add additional capacity to, our infrastructure assets;
the level of workovers and recompletions of wells on existing pad sites to which our infrastructure assets are connected;
our ability to identify and execute organic expansion projects to capture incremental volumes from Oasis Petroleum and third parties;
our ability to compete for volumes from successful new wells in the areas in which we operate outside of our dedicated acreage;
our ability to provide crude oil, natural gas and water-related midstream services with respect to volumes produced on acreage that has been released from commitments with our competitors; and
our ability to obtain financing for acquiring incremental assets in dropdown transactions from Oasis Petroleum.
We actively monitor producer activity in the areas served by our infrastructure assets to identify opportunities to connect new wells to our gathering systems.
Adjusted EBITDA and Distributable Cash Flow
We define Adjusted EBITDA as earnings before interest expense (net of capitalized interest), income taxes, depreciation, amortization, impairment, equity-based compensation expenses and other similar non-cash adjustments. We define Adjusted EBITDA attributable to the Partnership as Adjusted EBITDA less Adjusted EBITDA attributable to Oasis Petroleum’s retained interests in our DevCos. We define Distributable Cash Flow as Adjusted EBITDA attributable to the Partnership less cash paid for interest and maintenance capital expenditures attributable to the Partnership.
Adjusted EBITDA and Distributable Cash Flow are not presentations made in accordance with GAAP. These non-GAAP supplemental financial measures may be used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies, to assess:
our operating performance as compared to other publicly traded partnerships in the midstream energy industry, without regard to historical cost basis or, in the case of Adjusted EBITDA, financing methods;
the ability of our assets to generate sufficient cash flow to make distributions to our unitholders;
our ability to incur and service debt and fund capital expenditures; and
the viability of acquisitions and other capital expenditure projects and the returns on investment of various investment opportunities.

18


We believe that the presentation of Adjusted EBITDA and Distributable Cash Flow provides useful information to investors in assessing our financial condition and results of operations. The GAAP measures most directly comparable to Adjusted EBITDA and Distributable Cash Flow are net income and net cash provided by operating activities, respectively. Adjusted EBITDA and Distributable Cash Flow should not be considered as alternatives to GAAP net income, income from operations, net cash provided by operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Adjusted EBITDA and Distributable Cash Flow have important limitations as analytical tools because they exclude some but not all items that affect net income and net cash provided by operating activities. Adjusted EBITDA or Distributable Cash Flow should not be considered in isolation or as a substitute for analysis of our results as reported under GAAP. Additionally, because Adjusted EBITDA and Distributable Cash Flow may be defined differently by other companies in our industry, our definition of Adjusted EBITDA and Distributable Cash Flow may not be comparable to similarly titled measures of other companies, thereby diminishing their utility. For a further discussion of Adjusted EBITDA and Distributable Cash Flow and reconciliations of Adjusted EBITDA and Distributable Cash Flow to net income and net cash provided by operating activities, see “Non-GAAP Financial Measures” below.
Capital Expenditures
The midstream energy business is capital intensive; thus, our operations require capital investments to maintain, expand, upgrade or enhance our existing operations. Our capital requirements are categorized as either:
Maintenance Capital Expenditures, which are cash expenditures (including expenditures for the construction or development of new capital assets or the replacement, improvement or expansion of existing capital assets) made to maintain, over the long term, system operating capacity, operating income or revenue. Examples of maintenance capital expenditures are expenditures to repair, refurbish and replace pipelines, to maintain equipment reliability, integrity and safety and to comply with environmental laws and regulations. In addition, we designate a portion of our capital expenditures to connect new wells to maintain gathering throughput as maintenance capital expenditures to the extent such capital expenditures are necessary to maintain, over the long term, system operating capacity, operating income or revenue. Cash expenditures made solely for investment purposes will not be considered maintenance capital expenditures; or
Expansion Capital Expenditures , which are cash expenditures to acquire additional interests in our midstream assets and to construct new midstream infrastructure and those expenditures incurred in order to extend the useful lives of our assets, reduce costs, increase revenues or increase system throughput or capacity from current levels, including well connections that increase existing system operating capacity, operating income or revenue. Examples of expansion capital expenditures include the acquisition of additional interests in our DevCos and the construction, development or acquisition of additional midstream assets, in each case, to the extent such capital expenditures are expected to increase, over the long term, system operating capacity, operating income or revenue. In the future, if we make acquisitions that increase system operating capacity, operating income or revenue, the associated capital expenditures may also be considered expansion capital expenditures.
Direct Operating Expenses
We seek to maximize the profitability of our operations by effectively managing operating expenses. Direct operating expenses, which do not extend the useful life of existing property, plant and equipment, are primarily comprised of direct labor, utility costs, insurance premiums, third-party service provider costs, related property taxes and other non-income taxes, purchases of freshwater and expenditures to repair, refurbish and replace facilities and to maintain equipment reliability, integrity and safety.
Direct operating expenses fluctuate from period to period depending on the mix of activities performed during any specified period and the timing of these expenses. Because many of these expenses are fixed in nature, we expect to lower operating expenses as a percentage of revenue as we add incremental volumes onto our gathering systems. We will seek to manage our operating expenditures by scheduling periodic maintenance on our assets in order to minimize significant variability in these expenditures and their impact on our cash flow.
General and Administrative Expenses
Historically, our Predecessor’s general and administrative expenses included an allocation of charges for the management and operation of our assets by Oasis Petroleum for general and administrative services, such as legal, corporate recordkeeping, planning, budgeting, regulatory, accounting, billing, business development, treasury, insurance administration and claims processing, risk management, health, safety and environmental, information technology, human resources, investor relations, cash management and banking, payroll, internal audit, taxes and engineering. We are party to a 15-year services and secondment agreement with Oasis Petroleum (the “Services and Secondment Agreement”), pursuant to which Oasis Petroleum performs certain centralized corporate, general and administrative services for us, such as information technology, treasury, accounting, investor relations, human resources, legal services and other financial and administrative services.
In addition, Oasis Petroleum has seconded to us certain of its employees to operate, construct, manage and maintain our assets. The Services and Secondment Agreement requires us to reimburse Oasis Petroleum for direct general and administrative expenses incurred for the provision of these services. We determine the allocated general and administrative expenses

19


performed under the Services and Secondment Agreement using certain estimates and assumptions of the expenses attributable to our operations. Management believes these estimates and assumptions are reasonable. In addition, we incur costs as a publicly traded partnership which consist primarily of accounting and audit fees, legal fees, board and director expenses, and equity-based compensation expenses.
Items Affecting Comparability of Our Financial Condition and Results of Operations
This Quarterly Report on Form 10-Q includes results of operations attributable to our Predecessor for periods prior to September 25, 2017, the date on which we completed our initial public offering. Our future results of operations may not be comparable to our Predecessor’s historical results of operations for the following reasons:
Revenues . In connection with the initial public offering, we entered into 15-year contracts, effective as of January 1, 2018, for natural gas services (gathering, compression, processing and gas lift), crude oil services (gathering, stabilization, blending and storage), produced and flowback water services (gathering and disposal) and freshwater services (fracwater and flushwater supply and distribution) with Oasis Petroleum and its wholly owned subsidiaries. At the same time, we became a party to the long-term, FERC-regulated transportation services agreement governing the transportation of crude oil via pipeline from the Wild Basin area to Johnson’s Corner. Historically, our Predecessor had provided substantially all of their services to Oasis Petroleum operated wells at prevailing market rates. Following the closing of the initial public offering, we earn revenues under our long-term, fixed-fee commercial agreements with Oasis Petroleum.
Oasis Petroleum’s retained interests.  Our Predecessor’s results of operations included 100% of the revenues and expenses associated with OMS. At the closing of the initial public offering, OMS contributed to us a 100% , 10% and 40% equity interest in Bighorn DevCo, Bobcat DevCo and Beartooth DevCo, respectively. Following the closing of the initial public offering, we consolidated the financial position and results of operations of our equity interest in Bighorn DevCo under the voting interest consolidation model in accordance with GAAP. We consolidate the financial position and results of operations or our equity interests and Oasis Petroleum’s retained interest in Bobcat DevCo and Beartooth DevCo under the variable interest entity (“VIE”) consolidation model in accordance with GAAP. Oasis Petroleum’s retained portions of these interests are reflected as non-controlling interests in our condensed consolidated financial statements.
Excluded assets.  Certain midstream infrastructure assets, liabilities, revenues and expenses included in our Predecessor’s historical financial statements have been excluded from the businesses of the DevCos upon formation.
General and administrative expenses.  Our Predecessor’s general and administrative expenses included direct labor and indirect shared service expense allocations for support functions provided by Oasis Petroleum, as Oasis Petroleum provided substantial labor and overhead support for us. These support functions included general and administrative services, such as legal, corporate recordkeeping, planning, budgeting, regulatory, accounting, billing, business development, treasury, insurance administration and claims processing, risk management, health, safety and environmental, information technology, human resources, investor relations, cash management and banking, payroll, internal audit, taxes and engineering. Allocations were based primarily on headcount and direct usage during the respective periods of operations. We believe that these allocations were reasonable and reflected the utilization of services provided and benefits received, but may have differed from the cost that would have been incurred had we operated as a stand-alone entity for the years presented. Following the closing of the initial public offering, under our Services and Secondment Agreement, Oasis Petroleum charges us a combination of direct and indirect allocated charges for general and administrative services.
Financing . Historically, our Predecessor’s operations and capital expenditure requirements were financed solely with capital contributions from Oasis Petroleum. Our Predecessor recognized interest expense related to its funding   activity with Oasis Petroleum based on capital expenditures for the period using the weighted average effective interest rate of Oasis Petroleum’s long-term indebtedness.
In connection with the initial public offering, we entered into a revolving credit facility (the “Revolving Credit Facility”), which provides for an initial aggregate commitment amount of $200.0 million and matures on September 25, 2022 . At  March 31, 2018 $117.0 million  of borrowings were outstanding under the Revolving Credit Facility.
Income taxes . Our Predecessor determined income tax expense and related deferred tax balance sheet accounts on a separate return method for the periods prior to the initial public offering. Following the closing of the initial public offering, we are treated as a partnership for U.S. federal income tax purposes and, therefore, generally are not liable for entity-level federal income taxes.
Results of Operations
Revenues
Our revenues are primarily generated from charging fees for the midstream services we provide. These services include (i) gas gathering, compression, processing and gas lift services, with approximately 65,000 dedicated acres in the Wild Basin operating area and firm capacity for gas attributable to such acreage; (ii) crude gathering, stabilization, blending and storage

20


services, with approximately 65,000 dedicated acres in the Wild Basin operating area and firm capacity for crude oil attributable to such acreage; (iii) produced and flowback water gathering and disposal services, with approximately 65,000 dedicated acres in the Wild Basin operating area and firm capacity for produced and flowback water attributable to such acreage; (iv) produced and flowback water gathering and disposal services, with approximately 581,000 dedicated acres that includes the Alger, Cottonwood, Hebron, Indian Hills and Red Bank operating areas; and (v) freshwater supply and distribution services, with approximately 364,000 dedicated acres that includes the Hebron, Indian Hills, Red Bank and Wild Basin operating areas. In addition, we are party to a FERC-regulated crude transportation services agreement that has up to 75,000 barrels per day of operating capacity and firm capacity for committed shippers.
The following table summarizes our revenues for the periods presented:
 
Three Months Ended March 31,
 
2018
 
2017
 
Change
Operating results
(In thousands)
Revenues
 
 
 
 
 
Midstream services for Oasis
$
60,853

 
$
37,367

 
$
23,486

Midstream services for third parties
568

 
273

 
295

Total revenues
$
61,421

 
$
37,640

 
$
23,781

Three months ended March 31, 2018 as compared to three months ended March 31, 2017
Total midstream revenues increased $23.8 million to $61.4 million during the  three months ended March 31, 2018 as compared to the three months ended March 31, 2017 . This increase was driven by a $14.0 million increase related to higher natural gas and crude oil midstream service volumes, coupled with a $9.8 million increase related to higher water midstream service volumes.
Expenses and other income
The following table summarizes our operating expenses and other income and expenses for the periods presented:
 
Three Months Ended March 31,
 
2018
 
2017
 
Change
 
(In thousands)
Operating expenses
 
 
 
 
 
Direct operating
$
17,116

 
$
9,023

 
$
8,093

Depreciation and amortization
6,364

 
3,458

 
2,906

General and administrative
6,150

 
4,396

 
1,754

Total operating expenses
29,630

 
16,877

 
12,753

Operating income
31,791

 
20,763

 
11,028

Other income (expense)
 
 
 
 

Interest expense, net of capitalized interest
(262
)
 
(1,217
)
 
955

Other income (expense)

 
(2
)
 
2

Total other income (expense)
(262
)
 
(1,219
)
 
957

Income before income taxes
31,529

 
19,544

 
11,985

Income tax expense

 
(7,295
)
 
7,295

Net income
31,529

 
$
12,249

 
19,280

Less: Net income attributable to non-controlling interests
21,575

 
 
 
21,575

Net income attributable to Oasis Midstream Partners LP
$
9,954

 
 
 
$
9,954

Three months ended March 31, 2018 as compared to three months ended March 31, 2017
Direct operating expenses. The $8.1 million increase  for the three months ended March 31, 2018  as compared to the three months ended March 31, 2017 was primarily driven by a $3.6 million increase related to produced and flowback water direct operating costs as a result of higher produced and flowback water volumes, coupled with a $2.8 million increase related to higher natural gas direct operating costs due to increased natural gas processing volumes and a $1.4 million increase related to higher crude oil direct operating costs due to increased crude oil gathering and transportation volumes.

21


Depreciation and amortization. Depreciation and amortization expense increased $2.9 million to $6.4 million for the three months ended March 31, 2018  as compared to three months ended March 31, 2017 , primarily as a result of additional assets placed into service.
General and administrative (“G&A”) expenses. G&A expenses include direct labor and allocated costs of overhead support provided by Oasis Petroleum, such as legal, corporate recordkeeping, planning, budgeting, regulatory, accounting, billing, business development, treasury, insurance administration and claims processing, risk management, health, safety and environmental, information technology, human resources, investor relations, cash management and banking, payroll, internal audit, taxes and engineering. The increase of $1.8 million in our G&A expenses for the three months ended March 31, 2018 as compared to three months ended March 31, 2017 was primarily a result of increased employee compensation as a result of organizational growth.
Interest expense. Interest expense, net of capitalized interest, decreased $1.0 million to $0.3 million for the three months ended March 31, 2018 . This decrease was primarily attributable to a lower weighted average borrowing rate on our Revolving Credit Facility compared to the weighted average borrowing rate of Oasis Petroleum’s long-term indebtedness used to fund the operations of our Predecessor.
Income tax expense. The Partnership is not a taxable entity for U.S. federal income tax purposes and taxes are generally borne by our partners through the allocation of taxable income. Income tax expense for the three months ended March 31, 2017 was recorded at 37.3% of pre-tax net income.
Liquidity and Capital Resources
Our primary sources of liquidity include cash generated from operations and borrowings under our Revolving Credit Facility. We believe cash generated from these sources will be sufficient to meet our short-term working capital needs, long-term capital expenditure requirements and quarterly cash distributions. As a result, we expect to fund future expansion capital expenditures and acquisitions primarily from a combination of borrowings under our Revolving Credit Facility and, if necessary, the issuance of additional equity or debt securities. We expect our future cash requirements relating to working capital, maintenance capital expenditures and quarterly cash distributions to our unitholders will be funded from cash flows internally generated from our operations.
Our cash flows for the three months ended March 31, 2018 and 2017 are presented below:
 
Three Months Ended March 31,
 
2018
 
2017
 
(In thousands)
Net cash provided by operating activities
$
74,751

 
$
20,379

Net cash used in investing activities
(76,440
)
 
(23,814
)
Net cash provided by financing activities
4,854

 
3,435

Increase in cash and cash equivalents
$
3,165

 
$

Cash flows provided by operating activities
Net cash provided by operating activities was $74.8 million and $20.4 million for the three months ended March 31, 2018 and 2017 , respectively. The increase in cash flows from operating activities for the three months ended March 31, 2018 as compared to 2017 was primarily due to an increase in net income as a result of higher throughput volumes on our systems.
Cash flows used in investing activities
Net cash used in investing activities was $76.4 million and $23.8 million for the three months ended March 31, 2018 and 2017 , respectively. The increase in net cash used in investing activities for the three months ended March 31, 2018 as compared to 2017 was attributable to the capital spending on our second Wild Basin gas plant and the development of additional infrastructure in Wild Basin.
Our capital expenditures are summarized in the following table:

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Three Months Ended March 31, 2018
 
 
(In thousands)
Capital expenditures
 
Gross
 
Net
Maintenance capital expenditures
 
$
2,379

 
$
797

Expansion capital expenditures
 
78,867

 
48,663

Total capital expenditures
 
$
81,246

 
$
49,459

Our capital expenditures by DevCo are summarized in the following table:
 
 
 
 
Three Months Ended March 31, 2018
 
 
 
 
(In thousands)
DevCo
 
OMP Ownership
 
Gross
 
Net
Bighorn
 
100%
 
$
42,185

 
$
42,185

Bobcat
 
10%
 
27,834

 
2,783

Beartooth
 
40%
 
11,227

 
4,491

Total capital expenditures
 
 
 
$
81,246

 
$
49,459

__________________
Capital expenditures reflected in the tables above differ from capital expenditures shown in the statement of cash flows in our condensed consolidated financial statements because amounts reflected in the tables above include accrued capital expenditures.
Cash flows provided by financing activities
For the three months ended March 31, 2018 and 2017 , net cash provided by financing activities was $4.9 million and $3.4 million , respectively. The primary sources of net cash provided by financing activities for the three months ended March 31, 2018 was from net borrowings under our Revolving Credit Facility of $39.0 million , capital contributions from non-controlling interests of $15.2 million , offset by distributions to non-controlling interests of $38.3 million and distributions to unitholders of $11.0 million . The primary source of net cash provided by financing activities for the three months ended March 31, 2017 was capital contributions from Oasis Petroleum of $3.4 million .
Cash Distributions
Our partnership agreement requires that all of the Partnership’s available cash be distributed quarterly. Under the current cash distribution policy, the Partnership intends to distribute to the holders of common units and subordinated units on a quarterly basis at least the minimum quarterly distribution of $0.3750 per unit, or $1.50 on an annualized basis, to the extent the Partnership has sufficient cash after establishment of cash reserves and payment of fees and expenses, including payments to the General Partner and its affiliates. 
On February 26, 2018 , the Partnership paid the initial quarterly cash distribution to its unitholders of $0.0245 per unit related to the six days ended September 30, 2017 and $0.3750 per unit related to the three months ended December 31, 2017 . The third quarter distribution was prorated from the closing of the Partnership’s initial public offering on September 25, 2017 .
On  May 7, 2018 , the Board of Directors of the General Partner, declared the quarterly distribution for the first quarter of 2018 of  $0.3925  per unit. The distribution will be payable on  May 29, 2018  to unitholders of record as of  May 17, 2018 .
Non-GAAP Financial Measures
Cash Interest, Adjusted EBITDA and Distributable Cash Flow are supplemental non-GAAP financial measures that are used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. These non-GAAP financial measures should not be considered in isolation or as a substitute for interest expense, net income (loss), operating income (loss), net cash provided by (used in) operating activities or any other measures prepared under GAAP. Because Cash Interest, Adjusted EBITDA and Distributable Cash Flow exclude some but not all items that affect interest expense, net income and net cash provided by operating activities and may vary among companies, the amounts presented may not be comparable to similar metrics of other companies .
Cash Interest

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We define Cash Interest as interest expense plus capitalized interest less amortization of deferred financing costs included in interest expense. Cash Interest is not a measure of interest expense as determined by GAAP. Management believes that the presentation of Cash Interest provides useful additional information to investors and analysts for assessing the interest charges incurred on our debt, excluding non-cash amortization, and our ability to maintain compliance with our debt covenants.
The following table presents a reconciliation of the GAAP financial measure of interest expense, net of capitalized interest, to the non-GAAP financial measure of Cash Interest for the periods presented:
 
Three Months Ended March 31,
 
2018
 
2017
 
(In thousands)
Interest expense, net of capitalized interest
$
262

 
$
1,531

Capitalized interest
835

 
289

Amortization of deferred financing costs (1)
(116
)
 

Cash Interest
$
981

 
$
1,820

___________________
(1) Represents the amortization of deferred financing costs on the Revolving Credit Facility. See Note  7  to our unaudited condensed consolidated financial statements for a description of our long-term debt.
Adjusted EBITDA
We define Adjusted EBITDA as earnings before interest expense (net of capitalized interest), income taxes, depreciation, amortization, equity-based compensation expenses and other similar non-cash adjustments. Adjusted EBITDA should not be considered an alternative to net income, net cash provided by operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Management believes that the presentation of Adjusted EBITDA provides information useful to investors and analysts for assessing our results of operations, financial performance and our ability to generate cash from our business operations without regard to our financing methods or capital structure, coupled with our ability to maintain compliance with our debt covenants. The GAAP measures most directly comparable to Adjusted EBITDA are net income and net cash provided by operating activities, respectively.
Distributable Cash Flow
We define Distributable Cash Flow as Adjusted EBITDA attributable to the Partnership less Cash Interest and maintenance capital expenditures attributable to the Partnership. Distributable Cash Flow should not be considered an alternative to net income, net cash provided by operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Management believes that the presentation of Distributable Cash Flow provides information useful to investors and analysts for assessing our results of operations, financial performance and our ability to generate cash from our business operations without regard to our financing methods or capital structure, coupled with our ability to make distributions to our unitholders. The GAAP measures most directly comparable to Distributable Cash Flow are net income and net cash provided by operating activities, respectively.
The following table presents reconciliations of the GAAP financial measures of net income and net cash provided by operating activities to the non-GAAP financial measure of Adjusted EBITDA and Distributable Cash Flow for the periods presented:

24


 
Three Months Ended March 31,
 
2018
 
2017
 
(In thousands)
Net income
$
31,529

 
$
12,249

Income tax expense

 
7,295

Depreciation and amortization
6,364

 
3,458

Equity-based compensation expense
63

 
348

Interest expense, net of capitalized interest
262

 
1,217

Adjusted EBITDA
38,218

 
$
24,567

Less: Adjusted EBITDA attributable to non-controlling interests
24,496

 
 
Adjusted EBITDA attributable to Oasis Midstream Partners LP
13,722

 
 
Cash Interest attributable to Oasis Midstream Partners LP
981

 
 
Maintenance capital expenditures
796

 
 
Distributable Cash Flow attributable to Oasis Midstream Partners LP
$
11,945

 
 
 
 
 
 
Net cash provided by operating activities
$
74,751

 
$
20,379

Current tax expense

 
5,358

Interest expense, net of capitalized interest
262

 
1,217

Changes in working capital
(36,681
)
 
(2,387
)
Other non-cash adjustments
(114
)
 

Adjusted EBITDA
38,218

 
$
24,567

Less: Adjusted EBITDA attributable to non-controlling interests
24,496

 
 
Adjusted EBITDA attributable to Oasis Midstream Partners LP
13,722

 
 
Cash Interest attributable to Oasis Midstream Partners LP
981

 
 
Maintenance capital expenditures
796

 
 
Distributable Cash Flow attributable to Oasis Midstream Partners LP
$
11,945

 
 


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Critical Accounting Policies and Estimates
There have been no material changes to our critical accounting policies and estimates from those disclosed in our Annual Report on Form 10-K for the year ended December 31, 2017 other than as disclosed in Note 2 to our unaudited condensed consolidated financial statements.
Item 3. — Quantitative and Qualitative Disclosures About Market Risk
The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risk. The term “market risk” refers to the risk of loss arising from adverse changes in commodity prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures.
Concentration of customer credit risk. We are dependent on Oasis Petroleum as our most significant customer, and we expect to derive a substantial majority of our revenues from Oasis Petroleum for the foreseeable future. As a result, any event, whether in our dedicated areas or otherwise, that adversely affects Oasis Petroleum’s production, drilling schedule, financial condition, leverage, market reputation, liquidity, results of operations or cash flows may adversely affect our revenues and cash available for distribution. Further, we are subject to the risk of non-payment or non-performance by Oasis Petroleum. We cannot predict the extent to which Oasis Petroleum’s business would be impacted if conditions in the energy industry were to deteriorate, nor can we estimate the impact such conditions would have on Oasis Petroleum’s ability to execute its drilling and development program or to perform under our agreements. Any material non-payment or non-performance by Oasis Petroleum could reduce our ability to make distributions to our unitholders. We did not experience any significant defaults on accounts receivable for the three months ended March 31, 2018 .
Commodity price risk . We have limited direct exposure to risks associated with fluctuating commodity prices due to the nature of our business and our long-term, fixed-fee arrangements with Oasis Petroleum. However, to the extent that our future contractual arrangements with Oasis Petroleum or third parties do not provide for fixed-fee structures, we may become subject to commodity price risk. Additionally, as a substantial portion of our revenues are derived from Oasis Petroleum, we will be indirectly subject to risks associated with fluctuating commodity prices to the extent that lower commodity prices adversely affect Oasis Petroleum’s production, drilling schedule, financial condition, leverage, market reputation, liquidity, results of operations or cash flows.
Interest rate risk . We have a Revolving Credit Facility which provides for an initial aggregate commitment amount of $200.0 million . As of March 31, 2018 , we had $117.0 million of borrowings under the Revolving Credit Facility. Borrowings under the Revolving 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 Credit Agreement) 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 Credit Agreement). The applicable margin for borrowings under the Revolving Credit Facility is based on the Partnership’s most recently tested consolidated total leverage ratio and 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 Revolving Credit Facility is subject to a commitment fee ranging from 0.375% to 0.50%.
At  March 31, 2018 , the outstanding borrowings under our Revolving Credit Facility bore interest at LIBOR plus a 1.75% margin. We do not currently, but may in the future, utilize interest rate derivatives to mitigate interest rate exposure in efforts to reduce interest rate expense related to debt issued under our Revolving Credit Facility. Interest rate derivatives would be used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio.
Item 4. — Controls and Procedures
Evaluation of disclosure controls and procedures. As required by Rule 13a-15(b) under the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our Chief Executive Officer (“CEO”), our principal executive officer, and our Chief Financial Officer (“CFO”), our principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of March 31, 2018 . Our disclosure controls and procedures are designed to provide reasonable assurance that information required to be disclosed by us in the reports filed or submitted by us under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our CEO and CFO as appropriate, to allow timely decisions regarding required disclosure. Based on this evaluation, our CEO and CFO have concluded that our disclosure controls and procedures were effective at March 31, 2018 .

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Changes in internal control over financial reporting. There were no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that occurred during the three months ended March 31, 2018 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.


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PART II — OTHER INFORMATION
Item 1. — Legal Proceedings
Our operations are subject to a variety of risks and disputes normally incident to our business. As a result, we may, at any given time, be a defendant in various legal proceedings and litigation arising in the ordinary course of business. However, except as disclosed below, we are not currently subject to any potentially material litigation.We maintain insurance policies with insurers in amounts and with coverage and deductibles that we, with the advice of our insurance advisors and brokers, believe are reasonable and prudent. We cannot, however, assure our unitholders that this insurance will be adequate to protect us from all material expenses related to potential future claims for personal and property damage or that these levels of insurance will be available in the future at economical prices.
Mirada litigation. On March 23, 2017, Mirada filed a lawsuit against Oasis Petroleum, OPNA, and OMS, seeking monetary damages in excess of $100.0 million, declaratory relief, attorneys’ fees and costs (Mirada Energy, LLC, et al. v. Oasis Petroleum North America LLC, et al.; in the 334th Judicial District Court of Harris County, Texas; Case Number 2017-19911). In its original lawsuit, Mirada asserts that it is a working interest owner in certain acreage owned and operated by Oasis Petroleum in Wild Basin. Specifically, Mirada asserts that Oasis Petroleum has breached certain agreements by: (1) failing to allow Mirada to participate in Oasis Petroleum’s midstream operations in Wild Basin; (2) refusing to provide Mirada with information that Mirada contends is required under certain agreements and failing to provide information in a timely fashion; (3) failing to consult with Mirada and failing to obtain Mirada’s consent prior to drilling more than one well at a time in Wild Basin; and (4) by overstating the estimated costs of proposed well operations in Wild Basin. Mirada seeks a declaratory judgment that OPNA be removed as operator in Wild Basin at Mirada’s election and that Mirada be allowed to elect a new operator; that certain agreements apply to Oasis Petroleum and Mirada and Wild Basin with respect to this dispute; that Oasis Petroleum be required to provide all information within its possession regarding proposed or ongoing operations in Wild Basin; and that OPNA not be permitted to drill, or propose to drill, more than one well at a time in Wild Basin without obtaining Mirada’s consent. Mirada also seeks a declaratory judgment with respect to Oasis Petroleum’s current midstream operations in Wild Basin. Specifically, Mirada seeks a declaratory judgment that Mirada has a right to participate in Oasis Petroleum’s Wild Basin midstream operations, consisting of produced and flowback water disposal, crude oil gathering and gas gathering and processing; that, upon Mirada’s election to participate, Mirada is obligated to pay its proportionate costs of Oasis Petroleum’s midstream operations in Wild Basin; and that Mirada would then be entitled to receive a share of revenues from the midstream operations and would not be charged any amount for its use of these facilities for production from the “Contract Area.”
On June 30, 2017, Mirada amended its original petition to add a claim that Oasis Petroleum has breached certain agreements by charging Mirada for midstream services provided by its affiliates and to seek a declaratory judgment that Mirada is entitled to be paid its share of total proceeds from the sale of hydrocarbons received by OPNA or any affiliate of OPNA without deductions for midstream services provided by OPNA or its affiliates.
On February 2, 2018 and February 16, 2018, Mirada filed a second and third amended petition, respectively. In these filings, Mirada alleges new legal theories for being entitled to enforce the underlying contracts, and added Bighorn DevCo LLC, Bobcat DevCo LLC and Beartooth DevCo LLC as defendants, asserting that these entities were created in bad faith in an effort to avoid contractual obligations owed to Mirada. Mirada may further amend its petition from time to time to assert additional claims as well as defendants.
Oasis Petroleum believes that Mirada’s claims are without merit, that Oasis Petroleum has complied with its obligations under the applicable agreements and that some of Mirada’s claims are grounded in agreements which do not apply to Oasis Petroleum. Oasis Petroleum filed an answer denying all of Mirada’s claims and intends and continues to vigorously defend against Mirada’s claims and, to the extent we are made a party to the suit, we intend to vigorously defend ourselves against such claims. Discovery is ongoing, and each of the parties has made a number of procedural filings and motions, and additional filings and motions can be expected over the course of the claim. Trial is currently scheduled for May 2019. However, neither we nor Oasis Petroleum can predict or guarantee the ultimate outcome or resolution of such matter. If such matter were to be determined adversely to our or Oasis Petroleum’s interests, or if we or Oasis Petroleum were forced to settle such matter for a significant amount, such resolution or settlement could have a material adverse effect on our business, results of operations and financial condition. Such an adverse determination could materially impact Oasis Petroleum’s ability to operate its properties in Wild Basin or develop its identified drilling locations in Wild Basin on its current development schedule. A determination that Mirada has a right to participate in Oasis Petroleum’s midstream operations could materially reduce the interests of Oasis Petroleum and us in our current assets and future midstream opportunities and related revenues in Wild Basin. Under the Omnibus Agreement the Partnership entered into with Oasis Petroleum in connection with the closing of our initial public offering, Oasis Petroleum agreed to indemnify the Partnership for any losses resulting from this litigation. However, the Partnership cannot guarantee that such indemnity will fully protect the Partnership from the adverse consequences of any adverse ruling.

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Item 1A. — Risk Factors
Our business faces many risks. Any of the risks discussed elsewhere in this Form 10-Q and our other SEC filings could have a material impact on our business, financial position or results of operations. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also impair our business operations.
For a discussion of our potential risks and uncertainties, see the information in Item 1A. “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2017 (the “ 2017 Annual Report”). Other than as described below, there have been no material changes in our risk factors from those described in our 2017 Annual Report.
The 2015 final rule attempting to clarify federal jurisdiction under the Clean Water Act (“CWA”) over waters of the United States has had its implementation date extended to February 2020, while lawsuits challenging the 2015 rule resume in federal district court.
In June 2015, the U.S. Environmental Protection Agency (“EPA”) and the U.S. Army Corps of Engineers (“Corps”) published a final rule outlining their position on federal jurisdictional reach over waters of the United States, including jurisdictional wetlands, but legal challenges to this rule followed, and the rule was stayed nationwide, pending resolution of the court challenges. In January 2017, the U.S. Supreme Court accepted review of the rule to determine whether jurisdiction rests with the federal district or appellate courts and, in a decision issued in January 2018, held that legal challenges of the rule must be heard at the district rather than appellate court level. The stay on the 2015 rule was lifted in February 2018 and, in March 2018, a judge resumed a lawsuit in which a North Dakota-led coalition of states are challenging the June 2015 rule. Notwithstanding legal challenges to the 2015 rule, the EPA and the Corps published a final rule in February 2018 specifying that the contested 2015 rule would not take effect until February 6, 2020. As a result, future implementation of the 2015 rule is uncertain at this time. To the extent the 2015 rule or a revised rule expands the scope of the CWA’s jurisdiction in areas where we or our customers operate, it could impose additional permitting obligations on us and our customers.


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Item 6. — Exhibits
Exhibit
No.
 
Description of Exhibit
 
 
 
 
Sarbanes-Oxley Section 302 certification of Principal Executive Officer.
 
 
 
 
Sarbanes-Oxley Section 302 certification of Principal Financial Officer.
 
 
 
 
Sarbanes-Oxley Section 906 certification of Principal Executive Officer.
 
 
 
 
Sarbanes-Oxley Section 906 certification of Principal Financial Officer.
 
 
 
101.INS(a)
 
XBRL Instance Document.
 
 
101.SCH(a)
 
XBRL Schema Document.
 
 
101.CAL(a)
 
XBRL Calculation Linkbase Document.
 
 
101.DEF(a)
 
XBRL Definition Linkbase Document.
 
 
101.LAB(a)
 
XBRL Labels Linkbase Document.
 
 
101.PRE(a)
 
XBRL Presentation Linkbase Document.
___________________
(a)     Filed herewith.
(b)     Furnished herewith.



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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
OASIS MIDSTREAM PARTNERS LP
 
 
 
 
 
By: OMP GP LLC, its general partner
Date:
May 8, 2018
 
By:
 
/s/ Taylor L. Reid
 
 
 
 
 
 
 
Taylor L. Reid
 
 
 
 
 
 
 
Chief Executive Officer and Director
(Principal Executive Officer)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
By:
 
/s/ Richard N. Robuck
 
 
 
 
 
 
 
Richard N. Robuck
 
 
 
 
 
 
 
Senior Vice President and Chief Financial Officer
(Principal Accounting Officer and Principal Financial Officer)


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