S-1 1 d363619ds1.htm S-1 S-1
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Index to Financial Statements

As filed with the Securities and Exchange Commission on May 12, 2017

Registration No. 333-                

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

FORM S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

 

 

Oasis Midstream Partners LP

(Exact Name of Registrant as Specified in Its Charter)

 

 

 

Delaware   4922   47-1208855

(State or Other Jurisdiction of

Incorporation or Organization)

 

(Primary Standard Industrial

Classification Code Number)

 

(IRS Employer

Identification Number)

1001 Fannin Street, Suite 1500

Houston, Texas 77002

(281) 404-9500

(Address, Including Zip Code, and Telephone Number, Including Area Code, of Registrant’s Principal Executive Offices)

 

 

Taylor L. Reid

Chief Executive Officer

1001 Fannin Street, Suite 1500

Houston, Texas 77002

(281) 404-9500

(Name, Address, Including Zip Code, and Telephone Number, Including Area Code, of Agent for Service)

 

 

Copies to:

David P. Oelman

Thomas G. Zentner

Vinson & Elkins L.L.P.

1001 Fannin, Suite 2500

Houston, Texas 77002

(713) 758-2222

 

Matthew R. Pacey

Eric M. Willis

Kirkland & Ellis LLP

600 Travis Street, Suite 3300

Houston, Texas 77002

(713) 835-3600

 

 

Approximate date of commencement of proposed sale to the public: As soon as practicable

after this registration statement becomes effective.

If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box.   ☐

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.   ☐

If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, please check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.   ☐

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.   ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

 

Large accelerated filer      Accelerated filer  
Non-accelerated filer   ☒  (Do not check if a smaller reporting company)    Smaller reporting company  
     Emerging growth company  

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 7(a)(2)(B) of the Securities Act.  ☒

 

 

CALCULATION OF REGISTRATION FEE

 

Title of Each Class of

Securities to be Registered

 

Proposed
Maximum
Aggregate

Offering Price(1)(2)

  Amount of
Registration Fee

Common units representing limited partner interests

  $100,000,000   $11,590

 

 

(1) Includes common units issuable upon exercise of the underwriters’ option to purchase additional common units.
(2) Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(o).

 

 

The registrant hereby amends this registration statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment which specifically states that this registration statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the registration statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

 

 

 


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Index to Financial Statements

The information in this preliminary prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission becomes effective. This preliminary prospectus is not an offer to sell these securities and we are not soliciting an offer to buy these securities in any jurisdiction where the offer or sale is not permitted.

 

SUBJECT TO COMPLETION, DATED MAY 12, 2017

PROSPECTUS

Oasis Midstream Partners LP

Common Units

Representing Limited Partner Interests

This is the initial public offering of our common units representing limited partner interests. We are offering common units in this offering. No public market currently exists for our common units.

We intend to apply to list our common units on the New York Stock Exchange, or NYSE, under the symbol “OMP.”

We have granted the underwriters the option to purchase             additional common units on the same terms and conditions set forth above if the underwriters sell more than             common units in this offering.

We anticipate that the initial public offering price will be between $         and $         per common unit. We are an “emerging growth company” as that term is used in the Jumpstart Our Business Startups Act, or JOBS Act.

Investing in our common units involves risks. Please read “Risk Factors” beginning on page 24 of this prospectus.

These risks include the following:

 

  Because a substantial majority of our revenue currently is, and over the long term is expected to be, derived from Oasis Petroleum Inc., or Oasis, any development that materially and adversely affects Oasis’s operations, financial condition or market reputation could have a material and adverse impact on us.

 

  We may not generate sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our general partner, to enable us to pay the minimum quarterly distribution to our unitholders.

 

  Because of the natural decline in production from existing wells, our success depends, in part, on Oasis’s ability to replace declining production and our ability to secure new sources of production from Oasis or third parties. Any decrease in Oasis’s production could adversely affect our business and operating results.

 

  Substantially all of our assets are controlling ownership interests in each of our development companies (“DevCos”). Because our interests in our DevCos represent almost all of our cash-generating assets, our cash flow will depend entirely on the performance of our DevCos and their ability to distribute cash to us.

 

  On a pro forma basis, we would not have generated sufficient cash to support the payment of the minimum quarterly distribution on all of our units for the twelve months ended March 31, 2017.

 

  Our partnership agreement replaces our general partner’s fiduciary duties to holders of our common units with contractual standards governing its duties.

 

  Our general partner and its affiliates, including Oasis, which will own our general partner, may have conflicts of interest with us and limited duties to us and our unitholders, and they may favor their own interests to the detriment of us and our other common unitholders.

 

  Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors, which could reduce the price at which our common units will trade.

 

  Unitholders will experience immediate dilution in tangible net book value of $         per common unit.

 

  There is no existing market for our common units, and a trading market that will provide unitholders with adequate liquidity may not develop. The price of our common units may fluctuate significantly, which could cause unitholders to lose all or part of their investment.

 

  Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as us not being subject to a material amount of entity-level taxation. If the Internal Revenue Service, or IRS, were to treat us as a corporation for federal income tax purposes, or if we become subject to entity-level taxation for state tax purposes, our distributable cash would be substantially reduced.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

 

       Per Common Unit        Total  

Offering price to the public

       $                      $              

Underwriting discounts and commissions

       $                      $              

Proceeds to us (before expenses)

       $                      $              

The underwriters expect to deliver the common units to purchasers on or about             , 2017 through the book-entry facilities of The Depository Trust Company.

 

 

 

 

 

  Morgan Stanley   Citigroup   Wells Fargo Securities  

 

Credit Suisse   Deutsche Bank Securities   Goldman Sachs & Co. LLC   J.P. Morgan   RBC Capital Markets

 

        BOK Financial Securities, Inc.   BB&T Capital Markets   BBVA   BTIG        

 

    Capital One Securities   CIBC Capital Markets   Citizens Capital Markets, Inc.   Comerica Securities    

 

Heikkinen Energy Advisors   IBERIA Capital Partners L.L.C.   ING   Johnson Rice & Company L.L.C.

 

        Regions Securities LLC

 

Simmons & Company International

Energy Specialists of Piper Jaffray

 

Tudor, Pickering, Holt & Co.        

 

Prospectus dated             , 2017


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Index to Financial Statements

[Inside Cover Art]


Table of Contents
Index to Financial Statements

TABLE OF CONTENTS

 

SUMMARY

     1  

Overview

     1  

Our Assets

     3  

About Oasis

     6  

Our Relationship with Oasis

     8  

Business Strategies

     9  

Competitive Strengths

     10  

Formation Steps and Partnership Structure

     12  

Emerging Growth Company Status

     14  

Risk Factors

     14  

Our Management

     14  

Partnership Information

     15  

Summary of Conflicts of Interest and Fiduciary Duties

     15  

The Offering

     16  

Summary Historical and Pro Forma Financial Data

     21  

Non-GAAP Financial Measure

     23  

RISK FACTORS

     24  

Risks Related to Our Business

     24  

Risks Inherent in an Investment in Us

     53  

Tax Risks to Common Unitholders

     65  

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

     71  

USE OF PROCEEDS

     73  

CAPITALIZATION

     74  

DILUTION

     75  

OUR CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

     77  

General

     77  

Our Minimum Quarterly Distribution

     79  

Subordinated Units

     79  

Unaudited Pro Forma Adjusted EBITDA and Distributable Cash Flow for the Year Ended December 31, 2016 and the Twelve Months Ended March 31, 2017

     80  

Estimated Adjusted EBITDA and Distributable Cash Flow for the Twelve Months Ending June 30, 2018

     83  

Significant Forecast Assumptions

     86  

Regulatory, Industry and Economic Factors

     89  

HOW WE MAKE DISTRIBUTIONS TO OUR PARTNERS

     90  

General

     90  

Operating Surplus and Capital Surplus

     90  

Characterization of Cash Distributions

     92  

Subordination Period

     93  

Distributions From Operating Surplus During the Subordination Period

     95  

Distributions From Operating Surplus After the Subordination Period

     95  

General Partner Interest

     95  

Incentive Distribution Rights

     96  

Percentage Allocations of Distributions From Operating Surplus

     96  

Right to Reset Incentive Distribution Levels

     97  

Distributions From Capital Surplus

     99  

Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels

     100  

Distributions of Cash Upon Liquidation

     100  

SELECTED HISTORICAL AND PRO FORMA FINANCIAL DATA

     103  

Non-GAAP Financial Measure

     105  

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

     106  

Overview

     106  

How We Generate Revenues

     107  

How We Evaluate Our Operations

     107  

Items Affecting Comparability of Our Financial Condition and Results of Operations

     110  

Other Factors Impacting our Business

     111  

Results of Operations

     112  

Liquidity and Capital Resources

     114  

Revolving Credit Facility

     115  

Cash Flows

     116  

Critical Accounting Policies and Estimates

     118  

Impairment of Long-Lived Assets

     118  

Asset Retirement Obligations

     119  

Inflation

     119  

Off-Balance Sheet Arrangements

     120  

Seasonality

     120  

Quantitative and Qualitative Disclosures about Market Risk

     120  

INDUSTRY

     121  

Natural Gas Midstream Industry

     121  

Crude Oil Midstream Industry

     123  

Water Midstream Services Industry

     125  

Overview of the Williston Basin

     128  

BUSINESS

     131  

Overview

     131  

Our Assets

     133  
 

 

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About Oasis

     136  

Our Relationship with Oasis

     137  

Business Strategies

     137  

Competitive Strengths

     139  

Contractual Arrangements with Oasis

     140  

Competition

     142  

Title to Our Properties

     143  

Seasonality

     143  

Insurance

     143  

Pipeline Safety Regulation

     143  

Environmental and Occupational Health and Safety Matters

     144  

Employees

     152  

Legal Proceedings

     152  

MANAGEMENT

     154  

Management of Oasis Midstream Partners LP

     154  

Executive Officers and Directors of Our General Partner

     155  

Committees of the Board of Directors

     156  

EXECUTIVE COMPENSATION AND OTHER INFORMATION

     158  

Compensation Discussion and Analysis

     158  

Long Term Incentive Plan

     159  

Director Compensation

     162  

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

     163  

CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

     165  

Distributions and Payments to Our General Partner and Its Affiliates

     165  

Agreements with Affiliates in Connection with the Transactions

     166  

Other Contractual Relationships with Oasis

     168  

Procedures for Review, Approval and Ratification of Transactions with Related Persons

     168  

CONFLICTS OF INTEREST AND FIDUCIARY DUTIES

     170  

Conflicts of Interest

     170  

Fiduciary Duties of Our General Partner

     175  

DESCRIPTION OF THE COMMON UNITS

     177  

The Units

     177  

Transfer Agent and Registrar

     177  

Transfer of Common Units

     177  

THE PARTNERSHIP AGREEMENT

     179  

Organization and Duration

     179  

Purpose

     179  

Cash Distributions

     179  

Capital Contributions

     179  

Voting Rights

     180  

Applicable Law; Forum, Venue and Jurisdiction

     181  

Reimbursement of Partnership Litigation Costs

     181  

Limited Liability

     182  

Issuance of Additional Interests

     183  

Amendment of the Partnership Agreement

     183  

Merger, Consolidation, Conversion, Sale or Other Disposition of Assets

     185  

Dissolution

     186  

Liquidation and Distribution of Proceeds

     186  

Withdrawal or Removal of Our General Partner

     186  

Transfer of General Partner Interest

     187  

Transfer of Ownership Interests in the General Partner

     187  

Transfer of Subordinated Units and Incentive Distribution Rights

     187  

Change of Management Provisions

     188  

Limited Call Right

     189  

Non-Taxpaying Holders; Redemption

     189  

Non-Citizen Assignees; Redemption

     190  

Meetings; Voting

     190  

Voting Rights of Incentive Distribution Rights

     191  

Status as Limited Partner

     191  

Indemnification

     191  

Reimbursement of Expenses

     192  

Books and Reports

     192  

Right to Inspect Our Books and Records

     192  

Registration Rights

     193  

UNITS ELIGIBLE FOR FUTURE SALE

     194  

Stock Issued Under Employee Plans

     195  

MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES

     196  

Taxation of the Partnership

     197  

Tax Consequences of Common Unit Ownership

     198  

Tax Treatment of Operations

     203  

Disposition of Common Units

     204  

Uniformity of Common Units

     206  

Tax-Exempt Organizations and Other Investors

     207  

Administrative Matters

     208  

State, Local and Other Tax Considerations

     210  
 

 

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You should rely only on the information contained in this prospectus and any free writing prospectus prepared by us or on behalf of us or to the information which we have referred you. Neither we nor the underwriters have authorized anyone to provide you with information different from that contained in this prospectus and any free writing prospectus. We and the underwriters take no responsibility for, and can provide no assurance as to the reliability of, any other information that others may give you. We and the underwriters are offering to sell common units and seeking offers to buy common units only in jurisdictions where offers and sales are permitted. The information in this prospectus is accurate only as of the date of this prospectus, regardless of the time of delivery of this prospectus or any sale of the common units. Our business, financial condition, results of operations and prospects may have changed since that date.

This prospectus contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control. Please read “Risk Factors” and “Cautionary Statement Regarding Forward-Looking Statements.”

Industry and Market Data

The market data and certain other statistical information used throughout this prospectus are based on independent industry publications, government publications and other published independent sources. For example, statements noting our belief of the strategic location of our assets and the quality of the area in which we operate (including that of the Williston Basin) are based upon our experience in the industry and our analysis of information provided by subscription services used widely within the oil and natural gas industry. Information presented in such subscription service reports was not generated for purposes of this offering. Some data is also based on our good faith estimates. The industry in which we operate is subject to a high degree of uncertainty and risk due to a variety of factors, including those described in the section entitled “Risk Factors.” These and other factors may cause results to differ materially from those expressed in these publications.

Trademarks and Trade Names

We own or have rights to various trademarks, service marks and trade names that we use in connection with the operation of our business. This prospectus may also contain trademarks, service marks and trade names of third parties, which are the property of their respective owners. Our use or display of third parties’ trademarks, service marks, trade names or products in this prospectus is not intended to, and does not imply a relationship with, or endorsement or sponsorship by, us. Solely for convenience, the trademarks, service marks and trade names referred to in this prospectus may appear without the ®, TM or SM symbols, but such references are not intended to indicate, in any way, that we will not assert, to the fullest extent under applicable law, our rights or the right of the applicable licensor to these trademarks, service marks and trade names.

 

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Commonly Used Defined Terms

As used in this prospectus, unless the context indicates or otherwise requires, the following terms have the following meanings:

 

    “Oasis Midstream Partners LP,” “the Partnership,” “we,” “our,” “us” or like terms (i) when used in the present tense or prospectively refer to Oasis Midstream Partners LP and its consolidated subsidiaries and (ii) when used in the past tense, refer to our Predecessor;

 

    “Oasis” refers to Oasis Petroleum Inc. and its consolidated subsidiaries;

 

    “OMS Holdings” refers to OMS Holdings LLC, the sole member of our general partner and a wholly owned subsidiary of Oasis;

 

    “our general partner” or “OMP GP” refer to OMP GP LLC, a wholly owned subsidiary of OMS Holdings;

 

    “OMS” refers to Oasis Midstream Services LLC, a wholly owned subsidiary of OMS Holdings;

 

    “Predecessor” or like terms when used in a historical context refer to OMS, our accounting predecessor;

 

    “OPNA” refers to Oasis Petroleum North America LLC, a wholly owned subsidiary of Oasis, which owns substantially all of Oasis’s exploration and production assets;

 

    “OMP Operating” refers to OMP Operating LLC, a wholly owned subsidiary of the Partnership;

 

    “OPM” refers to Oasis Petroleum Marketing LLC, a wholly owned subsidiary of Oasis, which markets all of Oasis’s oil and natural gas volumes;

 

    “our directors” or “our officers” refer to the directors and officers, respectively, of our general partner;

 

    “our employees” refer to the employees of Oasis seconded to us or performing services on our and our general partner’s behalf;

 

    “Bighorn DevCo” refers to Bighorn DevCo LLC;

 

    “Bobcat DevCo” refers to Bobcat DevCo LLC;

 

    “Beartooth DevCo” refers to Beartooth DevCo LLC; and

 

    “DevCos” refers to our development companies, Bighorn DevCo, Bobcat DevCo and Beartooth DevCo, collectively.

 

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GLOSSARY OF TERMS

Barrel: One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil, NGLs or other liquid hydrocarbons.

Blowout: An uncontrolled flow of reservoir fluids into the wellbore, and sometimes catastrophically to the surface. A blowout may consist of produced water, oil, natural gas or a mixture of these. Blowouts can occur in all types of E&P operations, not just during drilling operations. If reservoir fluids flow into another formation and do not flow to the surface, the result is called an underground blowout. If the well experiencing a blowout has significant open-hole intervals, it is possible that the well will bridge over (or seal itself with rock fragments from collapsing formations) down-hole and intervention efforts will be averted.

Bo: Barrel of oil.

Boe: Barrels of oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of oil.

Boepd: Barrel of oil equivalent per day.

Bopd: Barrels of oil per day.

Bow: Barrels of water.

Bowpd: Barrels of water per day.

British thermal unit or BTU: The quantity of heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit

Completion: A generic term used to describe the assembly of down-hole tubulars and equipment required to enable safe and efficient production from an oil or natural gas well. The point at which the completion process begins may depend on the type and design of the well.

EPA: United States Environmental Protection Agency.

expansion capital expenditures: Expansion capital expenditures 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.

FERC: Federal Energy Regulatory Commission.

field: The general area encompassed by one or more oil or natural gas reservoirs or pools that are located on a single geologic feature, that are otherwise closely related to the same geologic feature (either structural or stratigraphic).

flushwater: Freshwater used to flush out existing wells in order to prevent downhole scaling.

Hydraulic fracturing: A stimulation treatment routinely performed on oil and natural gas wells in low-permeability reservoirs. Specially engineered fluids are pumped at high pressure and rate into the reservoir

 

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interval to be treated, causing a vertical fracture to open. The wings of the fracture extend away from the wellbore in opposing directions according to the natural stresses within the formation. Proppant, such as grains of sand of a particular size, is mixed with the treatment fluid to keep the fracture open when the treatment is complete. Hydraulic fracturing creates high-conductivity communication with a large area of formation and bypasses any damage that may exist in the near-wellbore area.

hydrocarbon: An organic compound containing only carbon and hydrogen.

maintenance capital expenditures: Maintenance capital expenditures 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.

MBo: One thousand barrels of oil.

MBoe: One thousand barrels of oil equivalent.

MBoepd: One thousand barrels of oil equivalent per day.

MBopd: One thousand barrels of oil per day.

MBow: One thousand barrels of water.

MBowpd: One thousand barrels of water per day.

MMBoe: One million barrels of oil equivalent.

MMBowpd: One million barrels of water per day.

MMBtupd: One million British thermal units per day.

Mscf: One thousand standard cubic feet.

MMscfpd: One million standard cubic feet per day.

natural gas: Hydrocarbon gas found in the earth, composed of methane, ethane, butane, propane and other gases.

NDIC: North Dakota Industrial Commission.

NGLs: Natural gas liquids, which consist primarily of ethane, propane, isobutane, normal butane and natural gasoline.

oil: Crude oil and condensate.

pd: Per day

Plug: A down-hole packer assembly used in a well to seal off or isolate a particular formation for testing, acidizing, cementing, etc.; also a type of plug used to seal off a well temporarily while the wellhead is removed.

 

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Pressure pumping: Services that include the pumping of liquids under pressure.

Proppant: Sized particles mixed with fracturing fluid to hold fractures open after a hydraulic fracturing treatment. In addition to naturally occurring sand grains, man-made or specially engineered proppants, such as resin-coated sand or high-strength ceramic materials like sintered bauxite, may also be used. Proppant materials are carefully sorted for size and sphericity to provide an efficient conduit for production of fluid from the reservoir to the wellbore.

Resource Play: Accumulation of hydrocarbons known to exist over a large area.

SEC: United States Securities and Exchange Commission.

Shale: A fine-grained, fissile, sedimentary rock formed by consolidation of clay- and silt-sized particles into thin, relatively impermeable layers.

SWD: Saltwater disposal.

throughput: The volume of product passing through a pipeline, plant, terminal or other facility.

Tubulars: A generic term pertaining to any type of oilfield pipe, such as drillpipe, drill collars, pup joints, casing, production tubing and pipeline.

Unconventional resource: An umbrella term for oil and natural gas that is produced by means that do not meet the criteria for conventional production. What has qualified as “unconventional” at any particular time is a complex function of resource characteristics, the available E&P technologies, the economic environment, and the scale, frequency and duration of production from the resource. Perceptions of these factors inevitably change over time and often differ among users of the term. At present, the term is used in reference to oil and natural gas resources whose porosity, permeability, fluid trapping mechanism, or other characteristics differ from conventional sandstone and carbonate reservoirs. Coalbed methane, gas hydrates, shale gas, fractured reservoirs and tight gas sands are considered unconventional resources.

Well stimulation: A treatment performed to restore or enhance the productivity of a well. Stimulation treatments fall into two main groups, hydraulic fracturing treatments and matrix treatments. Fracturing treatments are performed above the fracture pressure of the reservoir formation and create a highly conductive flow path between the reservoir and the wellbore. Matrix treatments are performed below the reservoir fracture pressure and generally are designed to restore the natural permeability of the reservoir following damage to the near-wellbore area. Stimulation in shale gas reservoirs typically takes the form of hydraulic fracturing treatments.

Wellbore: The physical conduit from surface into the hydrocarbon reservoir.

Workover: The process of performing major maintenance or remedial treatments on an oil or natural gas well. In many cases, workover implies the removal and replacement of the production tubing string after the well has been killed and a workover rig has been placed on location. Through-tubing workover operations, using coiled tubing, snubbing or slickline equipment, are routinely conducted to complete treatments or well service activities that avoid a full workover where the tubing is removed. This operation saves considerable time and expense.

 

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SUMMARY

This summary highlights some of the information contained in this prospectus and does not contain all of the information that may be important to you. You should read this entire prospectus and the documents to which we refer you before making an investment decision. You should carefully consider the information set forth under “Risk Factors,” “Cautionary Statement Regarding Forward-Looking Statements” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” as well as the audited historical, unaudited historical condensed and unaudited pro forma condensed financial statements and the related notes to those financial statements included elsewhere in this prospectus. The information presented in this prospectus assumes an initial public offering price of $        per common unit (the mid-point of the price range set forth on the cover page of this prospectus) and, unless otherwise indicated, that the underwriters’ option to purchase additional common units is not exercised.

Please read “Commonly Used Defined Terms” beginning on page iv hereof for definitions of certain terms used herein. Additionally, we include a glossary of some of the terms used in this prospectus as Appendix B.

Overview

We are a growth-oriented, fee-based master limited partnership formed by our sponsor, Oasis Petroleum Inc. (NYSE: OAS) (“Oasis”), 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 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 substantially all of our revenues through 15-year, fixed-fee contracts pursuant to which we provide crude oil, natural gas and water-related midstream services for Oasis. We expect to grow acquisitively through accretive, dropdown acquisitions, as well as organically as Oasis continues to develop its acreage in the Williston Basin. Additionally, we expect to grow by offering our services to third parties and through acquisitions of midstream assets from third parties.

Following this offering, Oasis intends for us to become its primary vehicle for midstream operations, which generate stable and growing cash flows and support the growth of its high quality assets in the Williston Basin and any other areas in which Oasis may operate in the future. We believe our midstream operations provide Oasis with numerous strategic, operational and financial benefits, which include lowering overall lease operating expenses, increasing operating efficiencies, and improving oil and gas differentials and realizations. These benefits are provided in part by giving Oasis access to numerous takeaway markets for its oil production, and by allowing Oasis to actively market its gas versus using third parties. We operate in two primary areas with developed midstream infrastructure, both of which are supported by significant acreage dedications from Oasis. In Wild Basin, Oasis has dedicated to us approximately 65,000 acres, of which approximately 29,000 are within Oasis’s current gross operated acreage position, and in which we have the right to provide oil, gas and water services to support Oasis’s existing and future production. Outside of the Wild Basin, Oasis has dedicated to us approximately 590,000 acres for produced water services, of which approximately 304,000 are within Oasis’s current gross operated acreage.

We will generate substantially all of our revenues through long-term, fee-based contractual arrangements with wholly owned subsidiaries of Oasis as described below, which minimize our direct exposure to commodity prices. Furthermore, we generally do not take ownership of the crude oil or natural gas that we handle for our customers, including Oasis. We believe our contractual arrangements will provide us with stable and predictable cash flows over the long-term. Oasis has also granted us a right of first offer, which we refer to as our ROFO, with respect to its retained interests in each of our operating subsidiaries, Bighorn DevCo, Bobcat DevCo and Beartooth DevCo (collectively, the “DevCos”), or any other midstream assets that Oasis builds with respect to its

 



 

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current acreage and elects to sell in the future (collectively, the “ROFO Assets”). In connection with the closing of this offering, we will enter 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 distribution) with Oasis and OMS. At the same time, we will become 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, which OMS previously entered into with OPM. This agreement is renewable at OPM’s option.

Historically, Oasis has financed, constructed and operated its midstream assets through its wholly owned subsidiary OMS. Following this offering, OMS will retain a portion of each of our DevCos, as described in more detail below. Oasis is contributing to us a larger percentage of those DevCos which have established operations, significant organic growth opportunities and limited expansion capital expenditure requirements. In contrast, Oasis is contributing to us a smaller percentage of those DevCos which have systems that require more substantial expansion capital expenditures for continued buildout. We believe this structure will allow us to receive stable and growing cash flows from the existing assets held by our DevCos while benefitting from Oasis’s continued funding, through OMS, of the majority of the expansion capital expenditures necessary to complete our less mature systems.

Oasis is an independent exploration and production (“E&P”) company focused on the acquisition and development of unconventional oil and natural gas resources in the North Dakota and Montana regions of the Williston Basin. As of December 31, 2016, Oasis held a highly concentrated and substantially wholly operated position composed of 730,267 gross (517,801 net) leasehold acres in the Williston Basin, of which approximately 94% was held by production. Oasis divides its acreage position into the following three categories:

 

       

Oasis’s Operating Areas

Category

 

Description

 

Areas Included in our
Dedication at IPO

 

Future Development Areas
(included in ROFO)

Core

  Deepest part of the basin with the best economics  

•  Wild Basin

•  Indian Hills

•  Alger

•  Southeast Red Bank

 

•  City of Williston(1)(2)

•  South Nesson(2)(3)

Extended core.

  Highly economic acreage position that is just outside of the core acreage  

•  Central Red Bank

•  Hebron (Montana)

 

•  Painted Woods(1)(2)

•  Missouri (Montana)(1)

•  Dublin(1)(2)

Fairway

  Economic acreage in proven, developed areas of the basin  

•  Cottonwood

•  Western Red Bank

 

•  Foreman Butte(1)(2)

•  Target (Montana)(1)

•  Far North Cottonwood(1)(2)

 

(1) No existing dedication for crude oil midstream services on undeveloped acreage.
(2) No existing dedication for gas midstream services on undeveloped acreage.
(3) Existing dedication for crude oil midstream services on a portion of the undeveloped acreage.

As of December 31, 2016, Oasis’s total leasehold position included 3,073 economic gross operated locations. Oasis’s core and extended core leasehold position contained an over 20-year inventory life, supported by approximately 1,614 highly economic gross operated locations. Oasis has the opportunity to develop a full suite of midstream services providing gathering, compression, processing and gas lift services to support its drilling and completion activities in its current operating areas that are not already dedicated to us or to third parties. We have a ROFO on these future midstream assets in the event Oasis builds assets in these areas and elects to sell them.

 



 

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The following table highlights key metrics by category across Oasis’s gross acreage position:

 

Category

   Oasis’s
Gross Operated
Locations
     Oasis’s
Gross Operated
Acreage(1)
     Percent of Oasis’s Locations
In Our Acreage  Dedication(2)

Core

     770        121,600        79

Extended core

     844        162,560        52

Fairway

     1,459        227,840        58
  

 

 

    

 

 

    

Total

     3,073        512,000        62
  

 

 

    

 

 

    

 

(1) Includes only gross acreage in drilling spacing units (DSUs) where Oasis currently counts economic gross operated locations.
(2) Substantially all of the acreage outside of our acreage dedication is subject to our ROFO. A portion of this acreage is not subject to dedications to third parties. To the extent acreage outside of our dedication is subject to third-party dedications, the ROFO would be applicable only if Oasis elects to build midstream assets in these areas when the existing third-party dedication lapses.

During the year ended December 31, 2016, Oasis had average daily production of 50,372 Boepd and completed and placed on production 57 gross (37.6 net) operated wells, all of which were completed on acreage dedicated to us. Additionally, approximately 85% of Oasis’s average daily production during the year ended December 31, 2016 took place on acreage dedicated to us. During the three months ended March 31, 2017, Oasis’s average daily production was 63,192 Boepd, and Oasis expects production to exceed 72,000 Boepd by the end of 2017 as it plans to complete a total of 76 gross (51.7 net) operated wells during the year. Approximately 97% of the expected 2017 gross completions will be on acreage dedicated to us.

The Oasis senior management team has extensive expertise in the oil and gas industry with experience in oil and gas plays across North America, including the Williston Basin while at Burlington Resources, and a proven track record of identifying, acquiring and executing large, repeatable development drilling programs. Oasis was founded in March of 2007, and the management team entered the Williston Basin in June 2007 with a 175,000 net acre acquisition, which the management team has since grown to 517,801 net acres while also developing and operating an extensive midstream asset portfolio. Our senior management team includes several of Oasis’s most senior officers, who are heavily involved in the planning and execution of Oasis’s future drilling and development program as well as their corresponding infrastructure expansion needs. We believe that our close relationship with Oasis strengthens our position as their primary vehicle for midstream operations going forward.

Our Assets

We operate our midstream infrastructure business through our three DevCos: Bighorn DevCo, Bobcat DevCo and Beartooth DevCo. The following table provides a summary of our assets, services and dedicated acreage (as of December 31, 2016, unless otherwise indicated) along with our ownership of these assets as of the closing of this offering.

 

DevCos

 

Areas Served

 

Service Lines

 

Current Status
of Asset

  Dedicated
Acreage / Oasis
Operated
Acreage
  Ownership at
IPO
 

Bighorn DevCo

 

•  Wild Basin

 

•  Gas processing

•  Crude stabilization

•  Crude blending

•  Crude storage

•  Crude transportation

 

•  Operational

•  Growth through organic expansion/minimal capital expenditures

  64,640 /
29,440
    100

 



 

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DevCos

 

Areas Served

 

Service Lines

 

Current Status
of Asset

  Dedicated
Acreage / Oasis
Operated
Acreage
  Ownership at
IPO
 

Bobcat DevCo

 

•  Wild Basin

 

•  Gas gathering

•  Gas compression

•  Gas lift

•  Crude gathering

•  Produced water gathering

•  Produced water disposal

 

 

•  Operational

•  Growth through organic expansion

•  Growth through expansion capital expenditures

  64,640 /

29,440

    10

Beartooth DevCo

 

•  Alger

•  Cottonwood

•  Hebron

•  Indian Hills

•  Red Bank

 

•  Produced water gathering

•  Produced water disposal

•  Freshwater distribution

 

•  Operational

•  Growth through organic expansion

•  Growth through expansion capital expenditures

  Produced
water

597,760 /
305,024

Freshwater
315,520 /
180,224

    35

Bighorn DevCo and Bobcat DevCo. We will own a 100% interest in Bighorn DevCo and a 10% interest in Bobcat DevCo, each of which has assets and operations in the Wild Basin operating area. Bighorn DevCo’s assets include gas processing and crude oil stabilization, blending, storage and transportation. These assets generate strong cash flows and the development of these assets is substantially complete, with additional organic growth expected through Oasis’s continued development of its acreage in the Wild Basin area. Accordingly, we expect Bighorn DevCo to incur limited expansion capital expenditures over time to support its organic growth. Bobcat DevCo’s assets include gas gathering, compression and gas lift, crude oil gathering and produced water gathering and disposal. Bobcat DevCo’s assets are operational, but the development of these assets are midcycle and will require more significant expansion capital expenditures over the near term, the majority of which will be funded by Oasis through OMS. We believe our 100% ownership in Bighorn DevCo and 10% ownership in Bobcat DevCo will generate significant and stable cash flows, while minimizing our expansion capital expenditure requirements. Both Bighorn DevCo and Bobcat DevCo hold assets in the Wild Basin area in McKenzie County, North Dakota, which is a key area of focus for Oasis’s drilling and development efforts. We believe our crude oil and natural gas gathering, processing and transportation assets provide an economic advantage to Oasis by providing critical infrastructure needed to move product to market and allow Oasis to realize substantially better pricing realizations on its produced oil and gas. Additionally, our existing midstream infrastructure in the basin facilitates more efficient execution of Oasis’s development plan by substantially minimizing the time necessary to connect new wells to market. Due to the high productivity of its wells in the Wild Basin area, Oasis is currently running two rigs in this area, and through OMS, has developed a full suite of crude oil, gas and water-related midstream assets in the Wild Basin area. Oasis, through OMS, has budgeted approximately $80 million in 2017 on midstream capital expenditures in support of its development of the area. Oasis has 29,440 gross operated acres inside of its 64,640 gross dedicated acreage area and 23 gross operated DSUs across the Wild Basin area. The Wild Basin area accounts for approximately one-third of Oasis’s 770 remaining core locations in the Williston Basin. Oasis had 72 gross operated producing Wild Basin wells at the end of 2016 and expects to complete 45 gross operated wells during 2017.

 



 

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Beartooth DevCo. We will own a 35% interest in Beartooth DevCo, which owns a significant portion of our water infrastructure assets. These assets, which gather and dispose of produced water, deliver freshwater for well completion and deliver freshwater for production optimization services, are predominately located in Oasis’s Alger, Cottonwood, Hebron, Indian Hills and Red Bank operating areas. Substantially all of Oasis’s acreage can be serviced by these assets with minimal additional expansion capital expenditures given the reach of our widely dispersed infrastructure systems currently in place, which can easily service additional wells through low cost connections to areas accessible by this infrastructure. We believe our 35% interest in Beartooth DevCo provides an attractive balance of current cash generation and growth potential, the majority of which will be funded by Oasis, through OMS. Crude oil cannot be efficiently produced in the Williston Basin without significant produced water transport and disposal capacity given the high water volumes produced alongside the oil. At the well site, crude oil and produced water are separated to extract the crude oil for sales and the produced water for proper disposal. We utilize our pipelines to gather produced water and move it to our saltwater disposal (“SWD”) facilities. Utilizing gathering pipelines is demonstrably more efficient than trucking water (the predominant alternative available in the Williston Basin today) and can lead to significantly higher production uptime during periods of harsh weather.

Oasis currently expects to begin operating two additional rigs in the Williston Basin during 2017 in areas located within our acreage dedication, which will result in increased produced water production. Beartooth DevCo holds strategically located produced water gathering pipeline systems spanning 310 miles that connect 570 oil and natural gas producing wells to our SWD well sites. Freshwater distribution systems play an integral role in the well completion and the ongoing production process. Beartooth DevCo also holds strategically located freshwater pipelines spanning 265 miles that connect 313 oil and natural gas producing wells. In addition to being critical for oil producers, we believe our water assets are highly efficient because they deliver high rates of availability and operational reliability and can be operated at what we consider to be relatively low costs. Our water assets are designed to withstand harsh winter conditions, significantly reducing shut-in times and accelerating the return to production for producing wells following winter storms that are common in the Williston Basin. Additionally, our water assets are strategically located within Oasis’s acreage position and are in close proximity to other operators in the Williston Basin, positioning us to become a leading provider of water-related midstream services in the Williston Basin. Oasis, through OMS, has budgeted approximately $20 million in 2017 on midstream capital expenditures to expand its water assets to support the projected volume growth that the new rigs will bring to these areas.

The following are detailed descriptions of our three DevCos:

Bighorn DevCo. Bighorn DevCo has substantial midstream assets, with limited additional expansion capital expenditure requirements, to support development in the Wild Basin area, including:

 

    an 80 MMscfpd natural gas processing plant with an enhanced propane recovery refrigeration unit;

 

    an approximately 20-mile, 10-inch, FERC-regulated, mainline crude oil pipeline to our sales destination, Johnson’s Corner, with up to 75,000 Bopd of operating capacity; and

 

    a crude oil blending, stabilization and storage facility with 180,000 barrels of storage capacity.

Bobcat DevCo. Bobcat DevCo has a significant midstream gathering system that continues to be developed as Oasis expands its drilling activities in the Wild Basin area, including:

 

    36 miles of six- and eight-inch crude oil gathering pipelines with initial capacity of 30,000 Bopd, which can be expanded to 45,000 Bopd, approximately 30% of which was constructed as of December 31, 2016 and was servicing all of Oasis’s recently completed wells;

 

    approximately 50 miles of eight-inch through 20-inch natural gas gathering pipelines with gathering capacity of up to 140 MMscfpd and field compression capabilities, approximately 30% of which was constructed as of December 31, 2016 and was servicing all of Oasis’s recently completed wells;

 



 

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    a natural gas lift system providing artificial lift throughout the field; and

 

    a produced water gathering and disposal system, consisting of three current SWD wells and 39 miles of eight- and ten-inch pipeline with capacity of approximately 45,000 Bowpd. Approximately 45% of the produced water gathering lines and three SWD wells were completed as of December 31, 2016 and were servicing all of Oasis’s recently completed wells.

Beartooth DevCo. Beartooth DevCo has an extensive produced water gathering, SWD and freshwater distribution system that continues to be developed as Oasis expands its drilling activities outside of the Wild Basin area, including:

 

    eight strategically located produced water gathering pipeline systems spanning 310 miles that connect 570 oil and natural gas producing wells to our SWD well sites;

 

    19 strategically located SWD wells that dispose of produced water from our produced water gathering pipeline systems or from third-party trucks;

 

    produced water gathering connections to approximately 68% of Oasis’s 837 gross operated producing wells that are outside of the Wild Basin; and

 

    265 miles of freshwater pipeline that connect to 313 oil and natural gas producing wells that are widely dispersed throughout our areas of operation, allowing for expansion to new wells in these areas for completion with minimal expansion capital expenditures.

Together, the DevCos are forecasting operating income of $117.8 million for the twelve-month period ending June 30, 2018, of which approximately 40% will be generated by our natural gas assets, 10% by our crude oil assets and 50% by our water-related midstream assets.

Existing Third-Party Dedications

We operate in two primary areas with developed midstream infrastructure, both of which are supported by significant acreage dedications from Oasis. In Wild Basin, Oasis has dedicated to us approximately 65,000 acres, of which approximately 29,000 are within Oasis’s current gross operated acreage position, and in which we have the right to provide oil, gas and water services to support Oasis’s existing and future production. In addition, Oasis has dedicated to us approximately 590,000 acres for produced water services, of which approximately 304,000 are within Oasis’s current gross operated acreage. Oasis has current acreage dedications to third parties for oil and natural gas services. Approximately 117,000 of Oasis’s gross operated acres are not subject to dedications for natural gas services and approximately 167,000 of Oasis’s gross operated acres are not subject to dedications for crude oil services. On dedicated acreage, if the third party dedication for oil and gas midstream services lapses on currently dedicated acreage, Oasis will have the right to dedicate that acreage to us for such services or to develop oil and natural gas midstream assets that would be subject to our ROFO in the event Oasis elects to sell them.

About Oasis

Oasis is an independent E&P company focused on the acquisition and development of unconventional oil and natural gas resources in the North Dakota and Montana regions of the Williston Basin. As of December 31, 2016, Oasis held a highly concentrated and substantially wholly operated position composed of 730,267 gross (517,801 net) leasehold acres in the Williston Basin, of which approximately 94% was held by production. As of December 31, 2016, Oasis’s core and extended core leasehold position contained an over 20-year inventory life, supported by approximately 1,614 highly economic gross drilling locations. Additionally, Oasis’s position contains another 1,459 economic locations in the fairway.

 



 

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For the year ended December 31, 2016, Oasis had (i) total oil and natural gas production of 50,372 Boepd; (ii) total E&P sales and other operating revenues of $704.7 million; and (iii) estimated net proved reserves of 305.1 MMBoe. Additionally, at March 31, 2017, Oasis had $6.2 billion of total assets, including $13.8 million of cash and cash equivalents, and total liquidity of $785.8 million, including availability under its revolving credit facility. Oasis had operating income of $20.1 million for the three months ended March 31, 2017.

The chart below illustrates the significant Williston Basin production growth demonstrated by Oasis since 2010. Following this offering, Oasis intends for us to become its primary vehicle for midstream operations, which generate stable and growing cash flows and support the growth of its high quality assets in the Williston Basin and any other areas in which Oasis may operate in the future. We anticipate providing critical crude oil, natural gas, produced water and freshwater services in support of Oasis’s growth. Oasis has publicly announced a production guidance growth rate for 2017 of approximately 35% at the midpoint as compared to its 2016 annual production rate of 50,372 Boepd.

 

LOGO

During 2016, Oasis spent $400 million on capital expenditures, operating two rigs in the Williston Basin and completing and placing on production 57 gross (37.6 net) operated Bakken and Three Forks wells, bringing the total number of gross Oasis-operated producing wells in the Williston Basin that target the Bakken and Three Forks formations to 909 as of December 31, 2016. As of December 31, 2016, Oasis had 83 gross operated wells waiting on completion in the Bakken and Three Forks formations. Oasis’s 2017 capital plan of $605 million contemplates completing and placing on production approximately 76 gross (51.7 net) operated wells, approximately 97% of which are on acreage dedicated to us, and includes $110 million of capital expenditures associated with midstream assets, of which approximately $100 million is to be spent on assets in acreage dedicated to us.

Oasis’s current operations are located exclusively in the Williston Basin, which covers 202,000 square miles in the Northern United States and Southern Canada. The Bakken and underlying Three Forks formations are the two primary reservoirs that Oasis is currently developing in the Williston Basin. According to the U.S. Energy Information Administration—U.S. Crude Oil and Natural Gas Proved Reserves, Year-End 2015 report, the Bakken and Three Forks shale formations contain technically recoverable reserves estimated at 5.0 billion barrels of oil, while North Dakota contains 7.3 trillion cubic feet of natural gas. The utilization of horizontal drilling and hydraulic fracturing has turned the Williston Basin into one of the most prolific crude oil producing basins in North America. The first horizontal Middle Bakken well was drilled in 2000, and as drilling techniques

 



 

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improved, production continued to increase. Since 2010, and despite a recent pull-back in activity related to oil price declines, major operators have entered the basin and crude oil production has increased by approximately 3.5 times from January 2010 to January 2017.

Contractual Arrangements with Oasis

In connection with the closing of this offering, we will enter into 15-year, fixed-fee contracts with OMS and other wholly owned subsidiaries of Oasis for (i) gas gathering, compression, processing and gas lift services with approximately 65,000 dedicated acres; (ii) crude gathering, stabilization, blending and storage services with approximately 65,000 dedicated acres; (iii) produced water gathering and disposal services with approximately 65,000 dedicated acres; (iv) produced water gathering and disposal services with approximately 590,000 dedicated acres that include the Alger, Cottonwood, Hebron, Indian Hills and Red Bank operating areas; and (v) freshwater distribution services with approximately 312,000 committed acres that includes the Hebron, Indian Hills and Red Bank operating areas. In addition, we will become a party to the long-term, fixed-fee agreement previously entered into by OMS and OPM providing for crude transportation services from the Wild Basin area to Johnson’s Corner through a FERC-regulated pipeline system that has up to 75,000 barrels per day of operating capacity and firm capacity for committed shippers. This agreement is renewable at OPM’s option.

Oasis has also granted us a ROFO with respect to its retained interests in the DevCos or any other midstream assets that Oasis elects to build with respect to its current acreage and elects to sell in the future. Please see “Certain Relationships and Related Party Transactions—Other Contractual Relationships with Oasis” for additional information on our contractual arrangements with Oasis.

Our Relationship with Oasis

Our relationship with Oasis is one of our principal strengths. Following the completion of this offering, Oasis will own an aggregate     % limited partner interest in us (or an aggregate     % limited partner interest in us if the underwriters exercise in full their option to purchase additional common units) and a 100% non-economic interest in our general partner, which owns all of our incentive distribution rights, or IDRs. Oasis will also indirectly own 90% of Bobcat DevCo and 65% of Beartooth DevCo after the completion of this offering. Oasis expects its Williston Basin operations to be the largest contributor to its total production growth, and Oasis intends to use us as an integral vehicle to support its Williston Basin production growth and the primary vehicle to grow the midstream infrastructure business that supports its production activities. We believe our assets are highly efficient because they have demonstrated high rates of availability and operational reliability, are designed to withstand harsh winter conditions and can be operated at what we consider to be relatively low costs. Our pipeline assets are demonstrably more efficient than trucking water, which is the predominant alternative available in the Williston Basin today. Additionally, our assets are strategically located within Oasis’s acreage position and are in close proximity to other operators in the Williston Basin, positioning us to become a leading provider of midstream services in the Williston Basin.

We intend to expand our business through the acquisition of retained interests in our DevCos, the acquisition of midstream assets that Oasis constructs, through OMS, in the Williston Basin and in any other oil or natural gas basins that Oasis may pursue, through selective acquisitions of complementary assets from third parties, both within and outside of the Williston Basin and by organic growth from the increased usage of our services by Oasis and other third parties as they continue to develop their oil and natural gas resources.

 



 

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Business Strategies

The primary components of our business strategy are:

Leverage Our Relationship with Oasis. We intend to leverage our relationship with Oasis to expand our asset base and increase our cash flows through:

 

    Dropdown Acquisitions from Oasis. Following this offering, Oasis will retain a 90% economic interest in Bobcat DevCo and a 65% economic interest in Beartooth DevCo, both of which are subject to our ROFO with Oasis. In addition, we anticipate acquiring assets that are not currently included in the DevCos that we anticipate Oasis will develop, through OMS, following this offering to support its production activities. Oasis’s future development areas provide it the opportunity to develop a full suite of crude oil, natural gas and water-related midstream assets similar to the infrastructure built in the Wild Basin area.

 

    Organic Growth. Our midstream infrastructure footprint services Oasis’s leading acreage position in the Williston Basin, which is composed of 3,073 gross operated locations. In 2017, Oasis plans to increase its active rig count from two to four rigs by mid-year and to bring on approximately 76 gross operated wells. During 2017, Oasis is targeting total capital expenditures of $495 million, excluding midstream capital expenditures of $110 million, approximately $100 million of which are allocated to assets in our DevCos. Accordingly, we anticipate that we will be positioned to increase our throughput volumes and cash flows as Oasis grows its production volumes through our crude oil, natural gas and water-related midstream assets. For the three months ended March 31, 2017, our pipelines gathered approximately 77% of the produced water volumes produced from Oasis’s operated wells and disposed of 87% of the produced water volumes produced from Oasis’s operated wells. We will seek to increase this percentage as we increase utilization on our existing pipelines and further develop our midstream infrastructure. Additionally, for the three months ended March 31, 2017, our crude oil and natural gas pipelines gathered 31,756 Boepd produced from Oasis’s operated wells in the Wild Basin area, which is forecasted to grow to 35,851 Boepd for the twelve months ending June 30, 2018.

Focus on Providing Services Under Long-Term, Fixed-Fee Contracts to Mitigate Direct Commodity Price Exposure and Enhance the Stability of Our Cash Flows. In connection with this offering, we will enter into 15-year contracts with Oasis and OMS 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 distribution). At the same time, we will become 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, which OMS previously entered into with OPM. This agreement is renewable at OPM’s option. We will generate substantially all of our revenues through these contracts. We will have minimal direct exposure to commodity prices, and we will generally not take ownership of the crude oil or natural gas that we gather, compress, process, terminal, store or transport for our customers, including Oasis. Due to this and the fee-based, long-term nature of our contracts, we believe these agreements will provide us with stable and predictable cash flows. Additionally, we intend to continue to pursue long-term, fee-based contracts with third parties.

Attract Third-Party Customers. We are seeking to expand our systems and increase the utilization of our existing midstream assets by attracting incremental volumes from other upstream oil and natural gas operators in the Williston Basin, and as such we are in active discussions with a number of potential customers. The scale of our assets and their strategic location near concentrated areas of current and expected future production make our geographic footprint difficult for competitors to replicate, thereby providing us the ability to gather incremental throughput volumes at a lower cost than new market entrants or competitors with less scale. We believe that our strategically located assets and our experience in designing, permitting, constructing and operating cost-efficient crude oil, natural gas and water-related midstream assets will allow us to grow our third-party business.

 



 

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Complete Accretive Acquisitions from Third Parties. In addition to growing our business organically and through dropdown acquisitions from Oasis, we intend to make accretive acquisitions of midstream assets from third parties. Leveraging our knowledge of, and expertise in, the Williston Basin, we intend to target and efficiently execute economically attractive acquisitions of midstream assets from third parties within and beyond our current area of operation. We also intend to explore accretive acquisition opportunities from third parties outside of the Williston Basin in support of any geographic expansion of Oasis’s operations.

Competitive Strengths

We believe that we will be able to successfully execute our business strategies because of the following strengths:

Our Strategic Affiliation with Oasis. We believe that, as a result of owning all of our IDRs,     % of our outstanding units following completion of this offering and a significant retained interest in the DevCos, Oasis is incentivized to promote and support our growth plan and to pursue projects that enhance the overall value of our business as well as its retained interests in the DevCos. We believe our assets are highly efficient, with demonstrated high rates of availability and operational reliability designed to withstand harsh winter conditions, and can be operated at what we consider to be relatively low costs. Additionally, our assets are strategically located within Oasis’s acreage position and are in close proximity to other operators in the Williston Basin, positioning us as a leading provider of midstream services in the Williston Basin.

 

    Dropdown Acquisition Opportunities. Following this offering, Oasis will retain a substantial ownership interest in our midstream systems through its 90% economic interest in Bobcat DevCo and 65% economic interest in Beartooth DevCo. In addition, following the completion of this offering, we believe Oasis, through OMS, will continue to build crude oil, natural gas and water-related midstream assets to support its production growth. We anticipate that we will have the opportunity to make accretive acquisitions from OMS by acquiring the remaining equity interests in both of our DevCos. In addition, we anticipate acquiring midstream assets that Oasis elects to develop and sell following this offering to support its production activities. We believe such development may provide OMS the ability to develop significant additional midstream assets.

 

    The Development of the Williston Basin is a Strategic Priority for Oasis. Oasis owns and operates an extensive and contiguous land position with a large inventory of leasehold acreage in the core areas of the Williston Basin, of which 94% was held by production as of December 31, 2016 and substantially all was operated. We believe we will directly benefit from Oasis’s continued development of its Williston Basin acreage, where it serves as operator with respect to substantially all of its net wells. As of December 31, 2016, Oasis’s inventory in the Williston Basin consisted of 3,073 identified potential drilling locations that are economic. Approximately 1,900 of Oasis’s drilling locations are located on acreage dedicated to us pursuant to one or more of our commercial agreements with Oasis and over 90% of these drilling locations are within 2 miles of our existing produced water gathering pipeline system. During 2017, Oasis plans to complete and place on production 76 gross (51.7 net) operated wells, of which approximately 97% are on acreage dedicated to us, and is targeting total capital expenditures of $495 million, excluding midstream capital expenditures of $110 million.

Strategically Located Midstream Assets. Our midstream assets are strategically located in the Williston Basin and provide critical midstream infrastructure to Oasis in a cost-efficient manner. We believe that the strategic location of our assets within the highly economic core of the Williston Basin, combined with our cost-advantaged midstream service offering, will enable us to attract volumes from third-party operators in the basin.

 

   

Demand for Midstream Infrastructure Services in the Williston Basin. The Wild Basin area in McKenzie County, North Dakota is the primary area of focus for Oasis’s drilling plan given its core location within the basin. We believe the extensive midstream infrastructure we are building in this

 



 

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area, as well as the existing assets within the remainder of the Williston Basin, provide a strategic footprint in the core of the Williston Basin and provide opportunities to connect other third-party operators. We believe our midstream assets will be able to compete for third-party business based on the cost-effective nature of our midstream services compared to the current alternatives for transportation of oil, gas and water in the basin. Additionally, due to the core location of our assets, we believe that extensive development will occur in and around our assets in the current commodity price environment, and future development activity will be highly levered to any commodity price recovery.

 

    Strategically Located Near Key Demand Centers. We believe our crude oil pipeline to Johnson’s Corner provides a highly strategic takeaway alternative for operators in the core of the Williston Basin. Johnson’s Corner is a receipt point for the Dakota Access Pipeline, which is expected to significantly improve in-basin pricing realizations for producers.

 

    Full-Service Operational Flexibility. In addition to our crude oil, natural gas and water gathering capabilities, our midstream assets include an 80 MMscfpd natural gas processing plant with an enhanced propane recovery refrigeration unit, crude oil blending, stabilization and storage facility, and a mainline FERC-regulated crude oil pipeline to our sales destination, Johnson’s Corner. As production increases in the Williston Basin, our interconnected system is constructed to provide optionality, which increases our growth prospects and value proposition to potential third-party customers.

Stable and Predictable Cash Flows. We provide substantially all of our gas gathering, compression, processing and gas lift; crude gathering, stabilization, blending and storage; produced water gathering and disposal; and freshwater distribution services to Oasis on a fixed-fee basis under 15-year contracts. Our assets are newly constructed, leading to relatively low maintenance capital expenditure requirements, which also enhances the stability of our cash flows. We believe that the operating history of Oasis and other companies in the Williston Basin has reduced development risk and increased the predictability of future production of new wells. This operating history, combined with the structure of our commercial contracts, is expected to promote the generation of stable and predictable cash flows. Based on historical performance and operating and economic assumptions, we expect the majority of the wells within Oasis’s estimated proved reserves as of December 31, 2016 to have producing lives in excess of 30 years.

Financial Flexibility and Strong Capital Structure. Given its retained ownership interests in our DevCos, Oasis will be responsible for its proportionate share of the total capital expenditures associated with any ongoing infrastructure development. In addition, at the closing of this offering, we expect to have no debt and an available borrowing capacity of $        million under a new $        million revolving credit facility. We intend to maintain a balanced capital structure which, when combined with our stable and predictable cash flows, should afford us efficient access to the capital markets at a competitive cost of capital that we expect will serve to enhance returns. We believe that our ownership structure, available borrowing capacity and ability to access the debt and equity capital markets will provide us with the financial flexibility to successfully execute our organic growth and acquisition strategies. We will seek to maintain a disciplined approach of financing acquisitions and growth projects with an appropriate mix of debt and equity.

Experienced Management and Operating Teams with Strong Execution Track Record. Through our relationship with Oasis, we will benefit from a significant pool of management talent, strong relationships throughout the energy industry and broad operational, technical and administrative infrastructure. These professionals have significant experience building, permitting and operating assets, including oil and natural gas gathering, natural gas processing, produced water gathering and disposal and freshwater distribution. We believe access to these personnel will, among other things, enhance the efficiency of our operations and accelerate our growth.

 



 

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Formation Steps and Partnership Structure

We are a Delaware limited partnership formed to serve as Oasis’s primary vehicle to support its production growth and grow its midstream business in the Williston Basin and in any other areas in which Oasis may operate in the future.

In connection with the closing of this offering, the following transactions will occur:

 

    Oasis and OMS will contribute a 100% interest in Bighorn DevCo, a 10% interest in Bobcat DevCo and a 35% interest in Beartooth DevCo to us;

 

    we will issue a non-economic general partner interest in us and all of our IDRs to our general partner;

 

    we will issue         common units and         subordinated units to OMS Holdings LLC, a wholly owned subsidiary of Oasis, representing an aggregate    % limited partner interest in us;

 

    we will issue         common units in this offering to the public, representing a    % limited partner interest in us;

 

    we will enter into a new $        million revolving credit facility, with no borrowings under the facility at the closing of this offering;

 

    we will enter into a 15-year gas gathering, compression, processing and gas lift agreement with OMS and other wholly owned subsidiaries of Oasis;

 

    we will enter into a 15-year crude gathering, stabilization, blending and storage agreement with OMS and other wholly owned subsidiaries of Oasis;

 

    we will enter into two 15-year produced water gathering and disposal agreements with OMS and other wholly owned subsidiaries of Oasis;

 

    we will enter into a 15-year freshwater distribution agreement with OMS and other wholly owned subsidiaries of Oasis;

 

    we will enter into a 15-year services and secondment agreement with Oasis; and

 

    we will enter into an omnibus agreement with Oasis.

Additionally, we will become a party to the long-term, FERC-regulated crude transportation services agreement that OMS previously entered into with OPM in 2016.

We have granted the underwriters a 30-day option to purchase up to an aggregate of         additional common units. Any net proceeds received from the exercise of this option will be distributed to Oasis. If the underwriters do not exercise this option in full or at all, the common units that would have been sold to the underwriters had they exercised the option in full will be issued to Oasis at the expiration of the option period. Accordingly, the exercise of the underwriters’ option will not affect the total number of common units outstanding.

We will use the net proceeds from this offering (including any net proceeds from the exercise of the underwriters’ option to purchase additional common units from us) as described in “Use of Proceeds.”

 



 

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The following is a simplified diagram of our ownership structure after giving effect to this offering and the related transactions:

 

LOGO

 

Common Units held by the public(1)(2)

                 

Common Units held by Oasis(1)

                 

Subordinated Units held by Oasis

                 

General Partner Interest(3)

         0.0
  

 

 

 

Total

     100
  

 

 

 

 

(1) Assumes no exercise of the underwriters’ option to purchase additional common units. Please read “—Formation Steps and Partnership Structure” for a description of the impact of an exercise of the option on the common unit ownership percentages.
(2) Excludes up to         common units that may be purchased by certain of our officers, directors, employees and other persons associated with us pursuant to a directed unit program, as described in more detail in “Underwriting.”
(3) Our general partner owns a non-economic general partner interest in us. Please read “How We Make Distributions To Our Partners—General Partner Interest.”

 



 

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Emerging Growth Company Status

As a partnership with less than $1.07 billion in revenue during its last fiscal year, we qualify as an “emerging growth company” as defined in the Jumpstart Our Business Startups Act, or the JOBS Act. As an emerging growth company, we may, for up to five years, take advantage of specified exemptions from reporting and other regulatory requirements that are otherwise applicable generally to public companies. These exemptions include:

 

    the presentation of only two years of audited financial statements and only two years of related Management’s Discussion and Analysis of Financial Condition and Results of Operations in the registration statement of which this prospectus is a part;

 

    exemption from the auditor attestation requirement on the effectiveness of our system of internal control over financial reporting;

 

    exemption from the adoption of new or revised financial accounting standards until they would apply to private companies;

 

    exemption from compliance with any new requirements adopted by the Public Company Accounting Oversight Board requiring mandatory audit firm rotation or a supplement to the auditor’s report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer; and

 

    reduced disclosure about executive compensation arrangements.

We may take advantage of these provisions until we are no longer an emerging growth company, which will occur on the earliest of (i) the last day of the fiscal year following the fifth anniversary of this offering, (ii) the last day of the fiscal year in which we have more than $1.07 billion in annual revenue, (iii) the date on which we have more than $700 million in market value of our common units held by non-affiliates and (iv) the date on which we issue more than $1 billion of non-convertible debt over a three-year period.

We have elected to take advantage of all of the applicable JOBS Act provisions, except that we will elect to opt out of the exemption that allows emerging growth companies to extend the transition period for complying with new or revised financial accounting standards. This election is irrevocable.

Accordingly, the information that we provide you may be different than what you may receive from other public companies in which you hold equity interests.

Risk Factors

An investment in our common units involves risks associated with our business, our partnership structure and the tax characteristics of our common units. Due to our relationship with Oasis, adverse developments or announcements concerning Oasis could materially adversely affect our business. These risks are described under “Risk Factors” and “Cautionary Statement Regarding Forward-Looking Statements.” You should carefully consider these risk factors together with all other information included in this prospectus.

Our Management

We are managed and operated by the board of directors and executive officers of our general partner, OMP GP. Oasis will own all of the membership interests in our general partner and will be entitled to appoint the entire board of directors of our general partner. Our unitholders will not be entitled to elect our general partner or its directors or otherwise directly or indirectly participate in our management or operation. All of the officers of our general partner are also officers and/or directors of Oasis. For information about the executive officers and directors of our general partner, please read “Management.”

 



 

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Immediately following the closing of this offering, our general partner will have            directors. Oasis will appoint all members to the board of directors of our general partner. In accordance with the NYSE’s phase-in rules, we will have at least three independent directors within one year of the date our common units are first listed on the NYSE. Our board has determined that                is independent under the independence standards of the NYSE.

In connection with the closing of this offering, we will enter into an omnibus agreement with Oasis and our general partner, pursuant to which we will agree upon certain aspects of our relationship with them, including our ROFO Assets, the provision by Oasis to us of certain administrative services, our agreement to reimburse Oasis for the cost of such services, certain indemnification and reimbursement obligations and other matters. We will also enter into a services and secondment agreement with Oasis, pursuant to which specified employees of Oasis will be seconded to us to provide operating services with respect to our business. Neither our general partner nor Oasis will receive any management fee or other compensation in connection with our general partner’s management of our business. However, prior to making any distribution on our common units, we will reimburse our general partner and its affiliates, including Oasis, for all expenses they incur and payments they make on our behalf pursuant to the omnibus agreement. Our partnership agreement provides that our general partner will determine the expenses that are allocable to us. Please read “Certain Relationships and Related Party Transactions—Agreements with Affiliates in Connection with the Transactions—Omnibus Agreement” and “—Services and Secondment Agreement.”

Our general partner will own all of our IDRs, which will entitle it to increasing percentages, up to a maximum of 50.0%, of the cash we distribute in excess of $         per unit per quarter after the closing of our initial public offering. Following the closing of this offering, Oasis will own         common units and         subordinated units prior to the exercise of the underwriters’ overallotment option. Please read “Certain Relationships and Related Party Transactions.”

Partnership Information

Our principal executive offices are located at 1001 Fannin Street, Suite 1500, Houston, Texas 77002, and our telephone number is (281) 404-9500. Our website is www.oasismidstream.com. We expect to make our periodic reports and other information filed with or furnished to the SEC available free of charge through our website as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information contained on our website or any other website is not incorporated by reference herein and does not constitute a part of this prospectus.

Summary of Conflicts of Interest and Fiduciary Duties

General. Under our partnership agreement, our general partner has a contractual duty to manage us in a manner it believes is not adverse to our interests. However, because our general partner is owned by Oasis, the officers and directors of our general partner also have a fiduciary duty to manage our general partner in a manner that is beneficial to Oasis. Consequently, conflicts of interest may arise in the future between us and our unitholders, on the one hand, and our general partner and its affiliates, including Oasis, on the other hand.

Partnership Agreement Replacement of Fiduciary Duties. Our partnership agreement limits the liability of, and replaces the duties owed by, our general partner and also restricts the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty. By purchasing a common unit, a common unitholder will agree to become bound by the provisions in our partnership agreement. Each unitholder is also treated as having consented to the provisions in the partnership agreement, including various actions and potential conflicts of interest contemplated in the partnership agreement that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law.

For a more detailed description of the conflicts of interest and duties of our general partner, please read “Conflicts of Interest and Fiduciary Duties.”

 



 

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THE OFFERING

 

Common units offered to the public

  


            common units.

               common units if the underwriters exercise their option to purchase additional common units in full.

Units outstanding after this offering

  


            common units and             subordinated units, for a total of limited partner units. If the underwriters do not exercise their option to purchase additional common units, in whole or in part, any remaining common units not purchased by the underwriters pursuant to the option will be issued to Oasis at the expiration of the option period for no additional consideration. Accordingly, the exercise of the underwriters’ option will not affect the total number of common units outstanding or the amount of cash needed to pay the minimum quarterly distribution on all units.

Use of proceeds

   We expect to receive net proceeds of approximately $        million from the sale of common units offered by this prospectus, based on the initial public offering price of $        per common unit after deducting underwriting discounts and commissions and estimated offering expenses. Our estimate assumes the underwriters’ option to purchase additional common units is not exercised. We intend to use the net proceeds from this offering (i) to make a distribution of approximately $        million to Oasis and (ii) to pay approximately $        million of origination fees and expenses related to our new revolving credit facility. Please read “Use of Proceeds.”
  

If the underwriters exercise in full their option to purchase additional common units, we expect to receive additional net proceeds of approximately $        million, after deducting underwriting discounts and commissions. We will use any net proceeds from the exercise of

the underwriters’ option to pay a distribution to Oasis.

Cash distributions

   Within 60 days after the end of each quarter, beginning with the quarter ending                , 2017, we expect to make a minimum quarterly distribution of $                 per common unit and subordinated unit ($                per common unit and subordinated unit on an annualized basis) to unitholders of record on the applicable record date. For the first quarter that we are publicly traded, we intend to pay a prorated distribution covering the period from the completion of this offering through                , 2017, based on the actual length of that period.
   The board of directors of our general partner will adopt a policy pursuant to which distributions for each quarter will be paid to the extent we have sufficient cash after establishment of cash reserves and payment of fees and expenses, including payments to our general partner and its affiliates. The board of directors of our general partner may change our distribution policy and the amount of distributions to be paid under our distribution policy at any time without unitholder approval and for any reason. Our ability to pay the minimum quarterly

 



 

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   distribution is subject to various restrictions and other factors described in more detail in “Our Cash Distribution Policy and Restrictions on Distributions.”
  

Our partnership agreement generally provides that we distribute cash each quarter during the subordination period in the following manner:

  

•       first, to the holders of common units, until each common unit has received the minimum quarterly distribution of $        plus any arrearages from prior quarters;

  

•       second, to the holders of subordinated units, until each subordinated unit has received the minimum quarterly distribution of $        ; and

  

•       third, to the holders of common units and subordinated units pro rata until each has received a distribution of $        .

   If cash distributions to our unitholders exceed $        per common unit and subordinated unit in any quarter, our unitholders and our general partner, as the holder of our IDRs, will receive distributions according to the following percentage allocations:
        
     Marginal Percentage
Interest in Distributions
 

Total Quarterly Distribution
Target Amount

   Unitholders     General
Partner (as
holder of
IDRs)
 

above $        up to $         

     85.0     15.0

above $        up to $        

     75.0     25.0

above $        

     50.0     50.0
   We refer to the additional increasing distributions to our general partner as “incentive distributions.” Please read “How We Make Distributions to Our Partners—Incentive Distribution Rights.”
   We believe, based on our financial forecast and related assumptions included in “Our Cash Distribution Policy and Restrictions on Distributions—Estimated Adjusted EBITDA and Distributable Cash Flow for the Twelve Months Ending June 30, 2018,” that we will have sufficient distributable cash flow to pay the minimum quarterly distribution of $        on all of our common units and subordinated units for the twelve months ending June 30, 2018. However, we do not have a legal or contractual obligation to pay quarterly distributions at the minimum quarterly distribution rate or at any other rate and there is no guarantee that we will pay distributions to our unitholders in any quarter. If we do not have sufficient cash, we may, but are under no obligation to, borrow funds to pay the minimum quarterly distribution to our unitholders. Please read “Our Cash Distribution Policy and Restrictions on Distributions.”
   Our unaudited pro forma distributable cash flow that would have been generated during the year ended December 31, 2016 and the twelve months ended March 31, 2017 was approximately $15.7 million and $19.2 million, respectively. The amount of distributable cash flow we must generate to support the payment of the minimum quarterly

 



 

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   distribution for four quarters on our common units and subordinated units to be outstanding immediately after this offering is approximately $        million (or an average of approximately $        million per quarter). As a result, for year ended December 31, 2016 and the twelve months ended March 31, 2017, on a pro forma basis, we would not have generated sufficient distributable cash to support the payment of the aggregate annualized minimum quarterly distribution on all of our common units and subordinated units. Please read “Our Cash Distribution Policy and Restrictions on Distributions—Unaudited Pro Forma Adjusted EBITDA and Distributable Cash Flow for the Year Ended December 31, 2016 and the Twelve Months Ended March 31, 2017.”

Subordinated units

   Oasis will initially own all of our subordinated units. The principal difference between our common units and subordinated units is that, for any quarter during the subordination period, holders of the subordinated units will not be entitled to receive any distribution from operating surplus until the common units have received the minimum quarterly distribution from operating surplus for such quarter plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. Subordinated units will not accrue arrearages.

Conversion of subordinated units

   The subordination period will end on the first business day after we have earned and paid an aggregate amount of at least $        (the minimum quarterly distribution on an annualized basis) multiplied by the total number of outstanding common and subordinated units for each of three consecutive, non-overlapping four-quarter periods ending on or after                 , 20         and there are no outstanding arrearages on our common units.
   Notwithstanding the foregoing, the subordination period will end on the first business day after we have paid an aggregate amount of at least $         (150.0% of the minimum quarterly distribution on an annualized basis) multiplied by the total number of outstanding common and subordinated units and the related distribution on the IDRs, for any four-quarter period ending on or after                , 20     and there are no outstanding arrearages on our common units.
   When the subordination period ends, all subordinated units will convert into common units on a one-for-one basis, and all common units will thereafter no longer be entitled to arrearages. Please read “How We Make Distributions to Our Partners—Subordination Period.”

 

Issuance of additional units

   Our partnership agreement authorizes us to issue an unlimited number of additional units without the approval of our unitholders. Please read “Units Eligible for Future Sale” and “The Partnership Agreement—Issuance of Additional Interests.”

 

Limited voting rights

   Our general partner will manage and operate us. Unlike the holders of common stock in a corporation, our unitholders will have only limited voting rights on matters affecting our business. Our unitholders will have no right to elect our general partner or its directors on an annual or other continuing basis. Our general partner may not be removed except for cause by a vote of the holders of at least 662/3% of the outstanding

 



 

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units, including any units owned by our general partner and its affiliates, voting together as a single class. In addition, any vote to remove our general partner during the subordination period must provide for the

election of a successor general partner by the holders of a majority of the common units and a majority of the subordinated units, voting as separate classes. Upon consummation of this offering, Oasis will own an aggregate of         % of our outstanding units (or         % of our outstanding units, if the underwriters exercise their option to purchase additional common units in full). This will provide Oasis the ability to prevent the removal of our general partner. Please read “The Partnership Agreement—Voting Rights.”

 

Limited call right

   If at any time our general partner and its affiliates (including Oasis) own more than 80% of the outstanding common units, our general partner has the right, but not the obligation, to purchase all of the remaining common units at a price equal to the greater of (1) the average of the daily closing price of our common units over the 20 trading days preceding the date three days before notice of exercise of the call right is first mailed and (2) the highest per-unit price paid by our general partner or any of its affiliates for our common units during the 90-day period preceding the date such notice is first mailed. Please read “The Partnership Agreement—Limited Call Right.”

 

Registration rights

   In connection with the completion of this offering, we intend to enter into a registration rights agreement with Oasis, pursuant to which we may be required to register the resale of our common units, subordinated units or other partnership interests directly or indirectly held by Oasis. We may be required pursuant to the registration rights agreement and our partnership agreement to undertake a future public or private offering. In addition, our partnership agreement grants certain registration rights to our general partner and its affiliates. Please read “Certain Relationships and Related Party Transactions—Agreements with Affiliates in Connection with the Transactions— Registration Rights Agreement” and “The Partnership Agreement—Registration Rights.”

 

Estimated ratio of taxable income to distributions

  


We estimate that if you own the common units you purchase in this offering through the record date for distributions for the period ending             , 20    , you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be less than         % of the cash distributed to you with respect to that period. For example, if you receive an annual distribution of $        per unit, we estimate that your average allocable federal taxable income per year will be no more than approximately $        per unit. Thereafter, the ratio of allocable taxable income to cash distributions to you could substantially increase. Please read “Material U.S. Federal Income Tax Consequences—Tax Consequences of Common Unit Ownership” for the basis of this estimate.

 



 

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Material federal income tax consequences

  


For a discussion of the material federal income tax consequences that may be relevant to prospective unitholders who are individual citizens or residents of the United States, please read “Material U.S. Federal Income Tax Consequences.”

 

Directed unit program

   At our request, the underwriters have reserved up to         % of the units offered hereby at the initial public offering price for officers, directors, employees and certain other persons associated with us. The number of units available for sale to the general public will be reduced to the extent such persons purchase such reserved units. Any reserved units not so purchased will be offered by the underwriters to the general public on the same basis as the other units offered hereby. The directed unit program will be arranged through one of our underwriters,                             .

 

Exchange listing

   We intend to apply to list our common units on the NYSE under the symbol “OMP.”

 



 

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SUMMARY HISTORICAL AND PRO FORMA FINANCIAL DATA

The following table presents summary historical financial data of our Predecessor and summary unaudited pro forma condensed financial data for the Partnership for the periods and as of the dates indicated. The summary historical unaudited financial data as of March 31, 2017 and for the three months ended March 31, 2017 and 2016 are derived from the unaudited historical condensed financial statements of the Predecessor appearing elsewhere in this prospectus. The summary historical financial data as of and for the years ended December 31, 2016 and 2015 is derived from the audited historical financial statements of the Predecessor appearing elsewhere in this prospectus. The following table should be read together with, and is qualified in its entirety by reference to, the historical financial statements and the accompanying notes included elsewhere in this prospectus. The table should also be read together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

In connection with the closing of this offering, Oasis will contribute to us economic interests in Bighorn DevCo, Bobcat DevCo and Beartooth DevCo. However, as required by U.S. generally accepted accounting principles (“GAAP”), we will consolidate 100% of the assets and operations of our DevCos in our financial statements and reflect a non-controlling interest adjustment for Oasis’s retained interests in our DevCos.

The summary unaudited pro forma condensed financial data presented in the following table for the three months ended March 31, 2017 and for the year ended December 31, 2016 is derived from the unaudited pro forma condensed financial statements included elsewhere in this prospectus. The unaudited pro forma condensed balance sheet assumes the offering and the related transactions occurred as of March 31, 2017, and the unaudited pro forma condensed statements of operations for the three months ended March 31, 2017 and for the year ended December 31, 2016 assume the offering and the related transactions occurred as of January 1, 2016.

The unaudited pro forma condensed financial statements give effect to the following:

 

    Oasis’s and OMS’s contribution of a 100% interest in Bighorn DevCo, a 10% interest in Bobcat DevCo and a 35% interest in Beartooth DevCo to us;

 

    our issuance of a non-economic general partner interest in us and all of our IDRs to our general partner;

 

    our issuance of            common units and         subordinated units to Oasis, representing an aggregate    % limited partner interest in us;

 

    our issuance of         common units to the public, representing a    % limited partner interest in us, and the receipt of $        million in net proceeds from this offering;

 

    our entry into a new $        million revolving credit facility, which we have assumed was not drawn during the pro forma periods presented;

 

    our entry into various long-term commercial agreements with OMS and other wholly owned subsidiaries of Oasis;

 

    our entry into a 15-year services and secondment agreement with Oasis;

 

    our entry into an omnibus agreement with Oasis; and

 

    the consummation of this offering and application of $        million of net proceeds to make a $         million distribution to Oasis and to pay $            million of origination fees and expenses related to our new revolving credit facility.

The unaudited pro forma condensed financial statements do not give effect to an estimated $2.5 million of incremental general and administrative expenses that we expect to incur annually as a result of being a publicly traded partnership.

 



 

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The following table presents the non-GAAP financial measure of Adjusted EBITDA, which we use in evaluating the performance of our business. For a definition of Adjusted EBITDA and a reconciliation to our most directly comparable financial measures calculated and presented in accordance with GAAP, please read “—Non-GAAP Financial Measure” below.

 

    Predecessor Historical     Pro Forma  
    Three Months Ended
March 31,
    Year Ended
December 31,
    Three Months
Ended March 31,
    Year Ended
December 31,
 
    2017     2016     2016     2015     2017     2016  
    (In thousands)  

Statement of Operations Data:

           

Revenues

           

Midstream services for Oasis

  $ 37,367     $ 29,814     $ 120,258     $ 104,675     $ 36,491     $ 92,889  

Midstream services for third parties

    273       4       594       21              
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total revenues

    37,640       29,818       120,852       104,696       36,491       92,889  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Operating expenses

           

Direct operating

    9,023       7,364       29,275       28,548       8,663       21,508  

Depreciation and amortization

    3,458       1,684       8,525       5,765       3,227       7,861  

Impairment

                      2,073              

General and administrative

    4,396       3,195       12,112       10,215       4,265       11,441  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total operating expenses

    16,877       12,243       49,912       46,601       16,155       40,810  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Operating income

    20,763       17,575       70,940       58,095       20,336       52,079  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Other income (expense)

    (2     14       (474     (800           (12

Interest expense, net of capitalized interest

    (1,217     (502     (5,481     (4,514     (282     (1,130
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Income before income taxes

    19,544       17,087       64,985       52,781       20,054       50,937  

Income tax expense

    (7,295     (6,653     (24,857     (20,339            
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income

  $ 12,249     $ 10,434     $ 40,128     $ 32,442     $ 20,054     $ 50,937  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income attributable to non-controlling interests(1)

                            13,467       35,127  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income attributable to Oasis Midstream Partners LP

  $ 12,249     $ 10,434     $ 40,128     $ 32,442     $ 6,587     $ 15,810  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income per limited partner unit (basic and diluted):

           

Common units

           

Subordinated units

           

Balance Sheet Data:

           

Cash

  $     $     $     $     $    

Property, plant and equipment, net

    441,314       300,437       431,535       265,409       407,236    

Total assets

    461,024       315,728       450,028       280,763      

Total liabilities

    113,317       92,263       118,353       75,907       22,834    

Total net parent investment/partners’ capital

    347,707       223,466       331,675       204,856      

Cash Flow Data:

           

Net cash provided by operating activities

  $ 20,379     $ 19,488     $ 72,086     $ 54,143      

Net cash used in investing activities

    (23,814     (27,445     (157,866     (120,234    

Net cash provided by financing activities

    3,435       7,957       85,780       66,091      

Other Financial Data:

           

Adjusted EBITDA(2)

  $ 24,567     $ 19,492     $ 79,912     $ 65,823     $ 23,901     $ 60,792  

 

(1) Represents the 90% and 65% non-controlling interests in the net income of Bobcat DevCo and Beartooth DevCo, respectively, retained by Oasis for the pro forma periods presented.
(2) For a discussion of the non-GAAP financial measure Adjusted EBITDA, including a reconciliation of Adjusted EBITDA to its most directly comparable financial measure calculated and presented in accordance with GAAP, please read “—Non-GAAP Financial Measure” below.

 



 

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Non-GAAP Financial Measure

Adjusted EBITDA

Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. This non-GAAP measure should not be considered in isolation or as a substitute for net income, operating income, net cash provided by operating activities or any other measures prepared under GAAP. Because Adjusted EBITDA excludes some but not all items that affect net income and may vary among companies, the amounts presented may not be comparable to similar metrics of other companies.

We define Adjusted EBITDA as earnings before interest expense (net of capitalized interest), income taxes, depreciation, amortization, impairment, stock-based compensation expenses and other non-cash adjustments. Adjusted EBITDA is not a measure of net income or cash flows as determined by GAAP. Management believes that the presentation of Adjusted EBITDA provides useful additional information to investors and analysts for assessing our results of operations, financial performance and our ability to generate cash from our business operations without regard to our financing methods or capital structure coupled with our ability to maintain compliance with our debt covenants.

The following table presents reconciliations of the GAAP financial measures of income before income taxes and net cash provided by operating activities to the non-GAAP financial measure of Adjusted EBITDA for the periods presented:

 

    Predecessor Historical     Pro Forma  
    Three Months Ended
March 31,
    Year Ended December 31,     Three
Months
Ended
March 31,
    Year Ended
December 31,
 
            2017                     2016                     2016                     2015                     2017                     2016          
   

(In thousands)

 

Income before income taxes

  $ 19,544     $ 17,087     $ 64,985     $ 52,781     $ 20,054     $ 50,937  

Depreciation and amortization

    3,458       1,684       8,525       5,765       3,227       7,861  

Stock-based compensation expenses

    348       219       911       690       338       863  

Impairment

                      2,073              

Interest expense, net of capitalized interest

    1,217       502       5,481       4,514       282       1,130  

Other non-cash adjustments

                10                   1  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Adjusted EBITDA

  $ 24,567     $ 19,492     $ 79,912     $ 65,823     $ 23,901     $ 60,792  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net cash provided by operating activities

  $ 20,379     $ 19,488     $ 72,086     $ 54,143      

Current tax expense

    5,358       5,799       24,069       16,796      

Interest expense, net of capitalized interest

    1,217       502       5,481       4,514      

Changes in working capital

    (2,387     (6,297     (21,734     (9,630    

Other non-cash adjustments

                10            
 

 

 

   

 

 

   

 

 

   

 

 

     

Adjusted EBITDA

  $ 24,567     $ 19,492     $ 79,912     $ 65,823      
 

 

 

   

 

 

   

 

 

   

 

 

     

 



 

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RISK FACTORS

Limited partner interests are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. You should carefully consider the following risk factors together with all of the other information included in this prospectus, including the matters addressed under “Cautionary Statement Regarding Forward-Looking Statements,” in evaluating an investment in our common units.

If any of the following risks were to occur, our business, financial condition, results of operations and distributable cash flow could be materially adversely affected. In that case, we may not be able to pay the minimum quarterly distribution on our common units, the trading price of our common units could decline and you could lose all or part of your investment.

Risks Related to Our Business

Because a substantial majority of our revenue currently is, and over the long term is expected to be, derived from Oasis, any development that materially and adversely affects Oasis’s operations, financial condition or market reputation could have a material and adverse impact on us.

For the year ended December 31, 2016, Oasis accounted for approximately 100% of our pro forma revenues. We are substantially dependent on Oasis as our most significant current customer, and we expect to derive a substantial majority of our revenues from Oasis for the foreseeable future. As a result, any event, whether in our areas of operation or otherwise, that adversely affects Oasis’s production, drilling and completion schedule, financial condition, leverage, market reputation, liquidity, results of operations or cash flows may adversely affect our revenues and distributable cash. Accordingly, we are indirectly subject to the business risks of Oasis, including, among others:

 

    a reduction in or slowing of Oasis’s anticipated drilling and production schedule, which would directly and adversely impact demand for our midstream infrastructure;

 

    the volatility of oil and natural gas prices, which could have a negative effect on the value of Oasis’s properties, its drilling programs or its ability to finance its operations;

 

    changes in regulations or statutes applicable to us or Oasis, which could have a negative effect on the value of our facilities or services or Oasis’s properties, its drilling programs or its ability to finance its operations;

 

    the availability of capital on an economic basis to fund Oasis’s exploration and development activities;

 

    Oasis’s ability to replace reserves;

 

    Oasis’s drilling and operating risks, including potential environmental liabilities;

 

    severe weather that may adversely affect Oasis’s production and operations;

 

    limitations on Oasis’s operations resulting from its debt restrictions and financial covenants;

 

    adverse effects of governmental and environmental regulation; and

 

    losses from pending or future litigation.

In addition, although Oasis has dedicated certain acreage to us under each of our commercial agreements with Oasis, these commercial agreements do not contain minimum volume commitments. Accordingly, if commodity prices decline substantially for a prolonged period, Oasis has the ability to substantially reduce its drilling and completion expenditures, which would decrease our throughput volumes from Oasis and related revenue streams under our commercial agreements.

Further, we are subject to the risk of non-payment or non-performance by Oasis, including with respect to our long-term contracts for natural gas gathering, compression, processing and gas lift; crude oil gathering,

 

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stabilization, blending, storage and transporting; produced water gathering and disposal; and freshwater distribution. If Oasis were to default under any of these contracts, we would have the contractual right to bring suit against Oasis to enforce the terms of such contract, and there can be no assurance that we would obtain a recovery, or that any such recovery that would fully compensate us for the consequence of such default. We neither can predict the extent to which Oasis’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’s ability to execute its drilling and development program or perform under our commercial agreements. Any material non-payment or non-performance by Oasis could reduce our ability to make distributions to our unitholders.

Also, due to our relationship with Oasis, our ability to access the capital markets, or the pricing or other terms of any capital markets transactions, may be adversely affected by any impairment to Oasis’s financial condition or adverse changes in its credit ratings. Further, if we were to seek a credit rating in the future, our credit rating may be adversely affected by Oasis’s leverage or its dependence on the cash flows from us to service its indebtedness, as credit rating agencies such as Standard & Poor’s Ratings Services and Moody’s Investors Service may consider the credit profile of Oasis and its affiliates because of their ownership interest in and control of us.

Any material limitation on our ability to access capital as a result of our relationship with Oasis or adverse changes at Oasis could limit our ability to obtain future financing under favorable terms, or at all, or could result in increased financing costs in the future. Similarly, material adverse changes at Oasis could negatively impact our unit price, limiting our ability to raise capital through equity issuances or debt financing, or could negatively affect our ability to engage in, expand or pursue our business activities, and could also prevent us from engaging in certain transactions that might otherwise be considered beneficial to us.

In the event Oasis elects to sell acreage that is dedicated to us to a third party, the third party’s financial condition could be materially worse than Oasis, and thus we could be subject to nonpayment or nonperformance by the third party.

In the event Oasis elects to sell acreage that is dedicated to us to a third party, the third party’s financial condition could be materially worse than Oasis’s. In such a case, we may be subject to risks of loss resulting from nonpayment or nonperformance by the third party, which risks may increase during periods of economic uncertainty. Furthermore, the third party may be subject to their own operating risks, which increases the risk that they may default on their obligations to us. Any material nonpayment or nonperformance by the third party could reduce our ability to make distributions to our unitholders.

We may not generate sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our general partner, to enable us to pay the minimum quarterly distribution to our unitholders.

In order to make our minimum quarterly distribution of $         per common unit and subordinated unit per quarter, or $         per unit per year, we will require available cash of approximately $         million per quarter, or approximately $         million per year, based on the common units and subordinated units outstanding immediately after completion of this offering. On a pro forma basis, we would not have generated sufficient distributable cash to support the payment of the minimum quarterly distribution on all our units for the year ended December 31, 2016 and the twelve months ended March 31, 2017. We may not generate sufficient cash flow each quarter to support the payment of the minimum quarterly distribution or to increase our quarterly distributions in the future.

The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:

 

    Oasis’s and our third-party customers’ ability to fund their drilling programs in our areas of operation;

 

    market prices of oil and natural gas and their effect on Oasis’s and third parties’ drilling schedule, as well as produced volumes;

 

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    the fees we charge, and the margins we realize, from our midstream infrastructure business;

 

    the volumes of natural gas and crude oil we gather, the volumes of produced water we collect or dispose of and the volumes of freshwater we distribute;

 

    our ability to make acquisitions of other midstream infrastructure assets, including any of the ROFO Assets, or other assets that complement or diversify our operations;

 

    the level of competition from other companies;

 

    costs associated with leaks or accidental releases of hydrocarbons or produced water into the environment, as a result of human error or otherwise;

 

    adverse weather conditions, natural disasters, vandalism and acts of terror;

 

    the level of our operating, maintenance and general and administrative costs;

 

    governmental regulations, including changes in governmental regulations, in our and our customers’ industries; and

 

    prevailing economic and market conditions.

In addition, the actual amount of our distributable cash will depend on other factors, including:

 

    the level and timing of capital expenditures we make;

 

    our debt service requirements and other liabilities;

 

    the level of our operating costs and expenses and the performance of our various facilities;

 

    our ability to make borrowings under our new revolving credit facility to pay distributions;

 

    fees and expenses of our general partner and its affiliates (including Oasis) we are required to reimburse (including the $2.5 million of annual incremental publicly traded partnership expenses we expect to incur); and

 

    other business risks affecting our cash levels.

For a description of additional restrictions and factors that may affect our ability to make cash distributions, please read “Our Cash Distribution Policy and Restrictions on Distributions.”

Because of the natural decline in production from existing wells, our success depends, in part, on Oasis’s ability to replace declining production and our ability to secure new sources of production from Oasis or third parties. Any decrease in Oasis’s production could adversely affect our business and operating results.

The level of crude oil and natural gas volumes handled by our midstream systems depends on the level of production from crude oil and natural gas wells dedicated to our midstream systems, which may be less than expected and which will naturally decline over time. In addition, the demand for our SWD services is directly correlated with the level of production from the crude oil and natural gas wells connected to our midstream system and the demand for our freshwater services is largely correlated with the level of our customers’ capital spending programs. To the extent Oasis reduces its activity or otherwise ceases to drill and complete wells within our acreage dedication, our revenues will be directly and adversely affected. In order to maintain or increase our expected cash flows, we will need to obtain additional throughput volumes from Oasis or third parties. The primary factors affecting our ability to obtain such additional throughput volumes include (i) the success of Oasis’s and our third-party customers’ drilling activities in our areas of operation and (ii) our ability to acquire additional well connections from Oasis or third parties. Therefore, our midstream infrastructure business is dependent upon active development in our areas of operation.

 

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We have no control over Oasis’s or other producers’ level of development and completion activity in our areas of operation, the amount of reserves associated with wells connected to our systems or the rate at which production from a well declines. In addition, we have no control over Oasis or other producers or their development plan decisions, which are affected by, among other things:

 

    the availability and cost of capital;

 

    prevailing and projected oil and natural gas prices;

 

    the proximity, capacity, cost and availability of gathering and transportation facilities, and other factors that result in differentials to benchmark prices;

 

    demand for oil and natural gas;

 

    levels of reserves;

 

    geologic considerations;

 

    environmental or other governmental laws and regulations, including the availability of drilling permits, the regulation of hydraulic fracturing, the potential removal of certain federal income tax deductions with respect to oil and natural gas exploration and development or additional state taxes on oil and natural gas extraction;

 

    shareholder activism or activities by non-governmental organizations to restrict the exploration, development and production of oil and natural gas; and

 

    the costs of producing oil and natural gas and the availability and costs of drilling rigs and other equipment.

Fluctuations in energy prices can also greatly affect the development of reserves. In general terms, the prices of oil, natural gas and other hydrocarbon products fluctuate in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control. These factors include worldwide economic conditions, weather conditions and seasonal trends, the levels of domestic production and consumer demand, the availability of imported oil and liquefied natural gas, or LNG, the availability of transportation systems with adequate capacity, the volatility and uncertainty of regional pricing differentials, the price and availability of alternative fuels, the effect of energy conservation measures, the nature and extent of governmental regulation and taxation, and the anticipated future prices of oil, natural gas, LNG and other commodities. Declines in commodity prices could have a negative impact on Oasis’s development and production activity, and if sustained, could lead to a material decrease in such activity. Sustained reductions in development or production activity in our areas of operation could lead to reduced utilization of our services.

In addition, substantially all of Oasis’s oil and natural gas production is sold to purchasers under contracts with market-based prices. The actual prices realized from the sale of oil and natural gas differ from the quoted NYMEX West Texas Intermediate and NYMEX Henry Hub prices, respectively, as a result of location differentials. Location differentials to NYMEX West Texas Intermediate and NYMEX Henry Hub prices, also known as basis differentials, result from variances in regional oil and natural gas prices compared to NYMEX West Texas Intermediate and NYMEX Henry Hub prices as a result of regional supply and demand factors. Oasis may experience differentials to NYMEX West Texas Intermediate and NYMEX Henry Hub prices in the future, which may be material.

Due to these and other factors, even if reserves are known to exist in areas served by our assets, producers may choose not to develop those reserves. If reductions in development activity result in our inability to maintain the current levels of throughput volumes on our midstream systems, those reductions could reduce our revenue and cash flow and adversely affect our ability to make cash distributions to our unitholders.

 

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Substantially all of our assets are controlling ownership interests in our DevCos. Because our interests in our DevCos represent almost all of our cash-generating assets, our cash flow will depend entirely on the performance of our DevCos and their ability to distribute cash to us.

We have a holding company structure, and the primary source of our earnings and cash flow consists exclusively of the earnings of and cash distributions from our DevCos. Therefore, our ability to make quarterly distributions to our unitholders will be almost entirely dependent upon the performance of our DevCos and their ability to distribute funds to us. We are the sole managing member of each of our DevCos, giving us the right to control and manage our DevCos.

The limited liability company agreement governing each DevCo requires the managing member of such DevCo to cause it to distribute all of its available cash each quarter, less the amounts of cash reserves that such managing member determines are necessary or appropriate in its reasonable discretion to provide for the proper conduct of such DevCo’s business.

The amount of cash each DevCo generates from its operations will fluctuate from quarter to quarter based on events and circumstances and other factors, as will the actual amount of cash each DevCo will have available for distribution to its members, including us. For a description of the events, circumstances and factors that may affect the cash distributions from our DevCos please read “—We may not generate sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our general partner, to enable us to pay the minimum quarterly distribution to our unitholders.”

On a pro forma basis, we would not have generated sufficient distributable cash to support the payment of the minimum quarterly distribution on all of our units for the year ended December 31, 2016 and the twelve months ended March 31, 2017.

We must generate approximately $         million of distributable cash to support the payment of the minimum quarterly distribution for four quarters on all of our common units and subordinated units that will be outstanding immediately following this offering. The amount of pro forma distributable cash generated during the year ended December 31, 2016 or the twelve months ended March 31, 2017 would not have been sufficient to support the payment of the full minimum quarterly distribution on our common units and subordinated units during such period. Specifically, the amount of pro forma distributable cash flow generated during the year ended December 31, 2016 and the twelve months ended March 31, 2017 would only have been sufficient to support a distribution of $         per common unit per quarter ($         per common unit on an annualized basis) and $         per common unit per quarter ($         per common unit on an annualized basis) on all of the common units, or only approximately     % and     % of the minimum quarterly distribution on all of our common units, respectively, and would not have supported distributions on our subordinated units. For a calculation of our ability to make cash distributions to our unitholders based on our pro forma results for the year ended December 31, 2016 and the twelve months ended March 31, 2017, please read “Our Cash Distribution Policy and Restrictions on Distributions.” If we are unable to generate sufficient distributable cash in future periods, we may not be able to support the payment of the full minimum quarterly distribution or any amount on our common units or subordinated units, in which event the market price of our common units may decline materially.

The assumptions underlying the forecast of distributable cash, as set forth in “Our Cash Distribution Policy and Restrictions on Distributions,” are inherently uncertain and subject to significant business, economic, financial, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those forecasted.

The forecast of distributable cash set forth in “Our Cash Distribution Policy and Restrictions on Distributions” includes our forecasted results of operations, Adjusted EBITDA and distributable cash for the

 

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twelve months ending June 30, 2018. Our ability to pay the full minimum quarterly distribution in the forecast period is based on a number of assumptions that may not prove to be correct and that are discussed in “Our Cash Distribution Policy and Restrictions on Distributions.” Management has prepared the financial forecast and has not received an opinion or report on it from our or any other independent auditor. The assumptions and estimates underlying the forecast are substantially driven by Oasis’s anticipated drilling and completion schedule and, although we consider our assumptions as to Oasis’s ability to maintain that schedule reasonable as of the date of this prospectus, those estimates and Oasis’s ability to achieve anticipated drilling and production targets are subject to a wide variety of significant business, economic and competitive risks and uncertainties that could cause actual results to differ materially from those contained in the forecast. If we do not achieve the forecasted results, we may not be able to pay the full minimum quarterly distribution or any amount on our common units or subordinated units, in which event the market price of our common units may decline materially.

We serve customers who are involved in drilling for, producing and transporting oil and natural gas. Adverse developments affecting the oil and natural gas industry or drilling activity, including sustained low oil or natural gas prices, a decline in oil or natural gas prices, reduced demand for oil and natural gas products and increased regulation of drilling and production, could have a material adverse effect on our results of operations.

Our midstream infrastructure business depends on our customers’ willingness to make operating and capital expenditures to develop and produce oil and natural gas in the United States. A reduction in drilling activity generally results in decreases in the volumes of crude oil, natural gas and produced water produced, which adversely impacts our revenues. Therefore, if these expenditures decline, our business is likely to be adversely affected.

Our customers’ willingness to engage in drilling and production of oil and natural gas depends largely upon prevailing industry conditions that are influenced by numerous factors over which our management has no control, such as:

 

    the supply of and demand for oil and natural gas;

 

    the level of prices, and expectations about future prices, of oil and natural gas;

 

    the cost of exploring for, developing, producing and delivering oil and natural gas, including fracturing services;

 

    the expected rate of decline of current oil and natural gas production;

 

    the discovery rates of new oil and natural gas reserves;

 

    available pipeline and other transportation capacity;

 

    lead times associated with acquiring equipment and products and availability of personnel;

 

    weather conditions, including hurricanes, tornadoes, wildfires, drought or man-made disasters that can affect oil and natural gas operations over a wide area, as well as local weather conditions in the Bakken Shale region of the Williston Basin in North Dakota that can have a significant impact on drilling activity in that region;

 

    regulations regarding flaring which may significantly increase the expenses associated with production;

 

    domestic and worldwide economic conditions;

 

    contractions in the credit market;

 

    political instability in certain oil and natural gas producing countries;

 

    the continued threat of terrorism and the impact of military and other action, including military action in the Middle East;

 

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    governmental regulations, including income tax laws or government incentive programs relating to the oil and natural gas industry and the policies of governments regarding the exploration for and production and development of their oil and natural gas reserves;

 

    the level of oil production by non-OPEC countries and the available excess production capacity within OPEC;

 

    oil refining capacity and shifts in end-customer preferences toward fuel efficiency;

 

    potential acceleration in the development, and the price and availability, of alternative fuels;

 

    the availability of water resources for use in hydraulic fracturing operations;

 

    public pressure on, and legislative and regulatory interest in, federal, state and local governments to ban, stop, significantly limit or regulate hydraulic fracturing operations;

 

    technical advances affecting energy consumption;

 

    the access to and cost of capital for oil and natural gas producers;

 

    merger and divestiture activity among oil and natural gas producers; and

 

    the impact of changing regulations and environmental and occupational health and safety rules and policies.

Our ROFO on Oasis’s retained assets is subject to risks and uncertainty, and ultimately we may not acquire any of those assets.

In connection with the closing of this offering, Oasis will grant us a ROFO with respect to its retained interests in our DevCos and any other midstream assets that Oasis builds with respect to its current acreage and elects to sell in the future. The consummation and timing of any acquisition by us of the assets covered by our ROFO will depend upon, among other things, our ability to reach an agreement with Oasis on price and other terms and our ability to obtain financing on acceptable terms. Moreover, Oasis is only obligated to offer to sell us the ROFO assets if Oasis decides to monetize such assets. Accordingly, we can provide no assurance whether, when or on what terms we will be able to successfully consummate any future acquisitions pursuant to our ROFO, and Oasis is under no obligation to accept any offer that we may choose to make or to enter into any commercial agreements with us. Additionally, we may decide not to exercise our ROFO when we are permitted to do so, and our decision will not be subject to unitholder approval.

Due to our lack of asset and geographic diversification, adverse developments in the areas in which we are located could adversely impact our financial condition, results of operations and cash flows and reduce our ability to make distributions to our unitholders.

Our midstream infrastructure assets are located exclusively in the North Dakota and Montana regions of the Williston Basin. As a result of this concentration, our financial condition, results of operations and cash flows are significantly dependent upon the demand for our midstream infrastructure assets in this area, and we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, market limitations, or other adverse events at one of our midstream infrastructure assets. Additionally, as we are substantially dependent on Oasis as our largest customer, if Oasis were to shift the geographic focus of its drilling activities away from the Williston Basin region, there could be a reduction in the development activity tied to our assets, which could reduce our revenue and cash flow and adversely affect our ability to make cash distributions to our unitholders.

We cannot predict the rate at which our customers will develop acreage that is dedicated to us or the areas they will decide to develop.

Our acreage dedication and commitments from Oasis cover midstream services in a number of areas that are at the early stages of development, in areas that Oasis is still determining whether to develop, and in areas where we may have to acquire operating assets from third parties. In addition, Oasis owns acreage in areas that are not

 

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dedicated to us. We cannot predict which of these areas Oasis will determine to develop and at what time. Oasis may decide to explore and develop areas in which we have a smaller operating interest in the midstream assets that service that area, or where the acreage is not dedicated to us, rather than areas in which we have a larger operating interest in the midstream assets that service that area. Oasis’s decision to develop acreage that is not dedicated to us or that we have a smaller operating interest in may adversely affect our business, financial condition, results of operations, cash flows and ability to make cash distributions. Likewise, we have no ability to influence when or where an unaffiliated third-party customer elects to develop acreage that is dedicated to us.

To the extent Oasis shifts the focus of its development away from the acreage dedicated to us and to other areas of operations where we do not have assets or acreage dedications, our results of operations and distributable cash could be adversely affected. In addition, because of contractual dedications to third-party oil and natural gas gathering companies, our opportunity to purchase additional midstream assets from Oasis is generally limited to midstream assets Oasis may develop in the City of Williston, South Nesson, Painted Woods, Missouri, Dublin, Target, Foreman Butte and Far North Cottonwood areas and other areas Oasis may develop in the future.

Under the terms of our long-term contracts with Oasis for natural gas gathering, compression, processing and gas lift; crude oil gathering, stabilization, blending, storage and transporting; produced water gathering and disposal; and freshwater distribution, we cannot guarantee that Oasis will focus on and continue to develop the acreage subject to our dedication. To the extent Oasis shifts the focus of its operations away from the areas dedicated to us and to its other areas where we do not have assets or operations, our business, financial condition, results of operations and ability to make cash distributions to our unitholders could be adversely affected.

In addition, Oasis has dedicated approximately 365,000 gross operated acres to third-party midstream service providers for natural gas services and approximately 315,000 gross operated acres for crude oil services. Accordingly, our ROFO on additional midstream assets from Oasis would be applicable only if Oasis elects to build and sell assets in these areas when the existing third-party dedication lapses. As a result, our opportunity to acquire oil and gas gathering, processing and transportation assets from Oasis, including pursuant to our ROFO, is generally limited, in the near term, to assets Oasis may develop on its current acreage in the City of Williston, South Nesson, Painted Woods, Missouri, Dublin, Target, Foreman Butte and Far North Cottonwood areas. If Oasis does not develop midstream assets in these areas or elects not to offer them for sale, our ability to grow through the acquisition of additional midstream assets from Oasis may be significantly and adversely impacted.

In the event Oasis elects to sell acreage that is dedicated to us to a third party, the third party’s financial condition could be materially worse than Oasis’s financial condition. In such a case, we may be subject to risks of loss resulting from nonpayment or nonperformance by the third party, which risks may increase during periods of economic uncertainty. Furthermore, the third party may be subject to their own operating and regulatory risks, which increases the risk that they may default on their obligations to us. Any material nonpayment or nonperformance by the third party could reduce our ability to make distributions to our unitholders.

We may be unable to grow by acquiring from Oasis the retained non-controlling interests in our DevCos or any other midstream assets that Oasis builds with respect to its current acreage and elects to sell in the future, which could limit our ability to increase our distributable cash.

Part of our strategy for growing our business and increasing distributions to our unitholders is dependent upon our ability to make acquisitions that increase our distributable cash. Part of the acquisition component of our growth strategy is based upon our expectation of future divestitures by Oasis to us of retained, acquired or developed midstream assets and portions of its retained, non-controlling interests in our DevCos. Our ROFO under our omnibus agreement only requires Oasis to allow us to make an offer with respect to its retained non-controlling interests in our DevCos or any other midstream assets that Oasis builds with respect to its current acreage to the extent Oasis elects to sell these interests. Oasis is under no obligation to sell its retained interests in our DevCos or to offer to sell us any additional midstream assets, we are under no obligation to buy any additional interests or assets from Oasis and we do

 

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not know when or if Oasis will decide to sell its retained interests in our DevCos or make any offers to sell assets to us. We may never purchase all or any portion of the retained, non-controlling interests in our DevCos or any other midstream assets from Oasis for several reasons, including the following:

 

    Oasis may choose not to sell these non-controlling interests or assets;

 

    we may not accept offers for these assets or make acceptable offers for these equity interests;

 

    we and Oasis may be unable to agree to terms acceptable to both parties;

 

    we may be unable to obtain financing to purchase these non-controlling interests or assets on acceptable terms or at all; or

 

    we may be prohibited by the terms of our debt agreements (including our new revolving credit facility) or other contracts from purchasing some or all of these non-controlling interests or assets, and Oasis may be prohibited by the terms of its debt agreements or other contracts from selling some or all of these non-controlling interests or assets. If we or Oasis must seek waivers of such provisions or refinance debt governed by such provisions in order to consummate a sale of these non-controlling interests or assets, we or Oasis may be unable to do so in a timely manner or at all.

We do not know when or if Oasis will decide to sell all or any portion of its non-controlling interests or will offer us any portion of its assets, and we can provide no assurance that we will be able to successfully consummate any future acquisition of all or any portion of such non-controlling interests in our DevCos or assets. Furthermore, if Oasis reduces its ownership interest in us, it may be less willing to sell to us its retained non-controlling interests in our DevCos or any other midstream assets. In addition, except for our ROFO, there are no restrictions on Oasis’s ability to transfer its non-controlling interests in our DevCos or any of its midstream assets to a third party or non-controlled affiliate. If we do not acquire all or a significant portion of the non-controlling interests in our DevCos held by Oasis or other midstream assets from Oasis, our ability to grow our business and increase our cash distributions to our unitholders may be significantly limited.

An unfavorable resolution of the Mirada litigation could have a material adverse effect on our business, financial condition, results of operations and cash flows.

On March 23, 2017, Mirada Energy, LLC, Mirada Wild Basin Holding Company, LLC and Mirada Energy Fund I, LLC, or Mirada, filed a lawsuit against Oasis and certain of its wholly owned subsidiaries in the 334th Judicial District Court of Harris County, Texas. Mirada asserts that it is a working interest owner in certain acreage owned and operated by Oasis and that Oasis has breached certain agreements its predecessors in interest previously entered into with Mirada, or its predecessors interest, with respect to such acreage. For further information regarding this lawsuit, please read “Business — Legal Proceedings.” We cannot predict the outcome of the Mirada lawsuit or the amount of time and expense that will be required to resolve the lawsuit. If such litigation were to be determined adversely to our or Oasis’s interests, or if we or Oasis 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’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’s midstream operations could materially reduce the interests of Oasis and us in our current assets and future midstream opportunities and related revenues in Wild Basin.

In our midstream infrastructure business, we may not be able to attract additional third-party gathering volumes, which could limit our ability to grow and diversify our customer base.

Part of our long-term growth strategy includes identifying additional opportunities to offer services to third parties. For the year ended December 31, 2016, Oasis accounted for approximately 100% of our pro forma revenues. Our ability to increase throughput on our midstream systems and any related revenue from third parties is subject to numerous factors beyond our control, including competition from third parties and the extent to which we have available capacity when requested by third parties. To the extent that we lack available capacity

 

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on our systems for third-party volumes or wells, we may not be able to compete effectively with third-party systems for additional volumes in our areas of operation.

Our efforts to attract new unaffiliated customers may be adversely affected by (i) our relationship with Oasis and the fact that a substantial majority of the capacity of our midstream systems will be necessary to service Oasis’s production and development and completion schedule and (ii) our desire to provide our gathering activities pursuant to fee-based contracts. As a result, we may not have the capacity to provide midstream infrastructure services to third parties and/or potential third-party customers may prefer to obtain midstream infrastructure services pursuant to other forms of contractual arrangements under which we would be required to assume direct commodity exposure.

The continued growth of our business will be affected by the willingness of potential third-party customers to outsource their midstream infrastructure services needs generally, and to us specifically rather than to our competitors. Potential third-party customers who are significant producers of crude oil and natural gas may develop their own midstream systems in lieu of using our systems. Currently, many E&P companies own and operate waste treatment, recovery and disposal facilities. In addition, most oilfield operators have numerous abandoned wells that could be licensed for use in the disposition of internally generated produced water and third-party produced water in competition with us. Potential third-party customers could decide to process and dispose of their produced water internally or develop their own midstream infrastructure systems for produced water gathering and freshwater distribution, which could negatively impact our financial position, results of operations, cash flows and ability to make cash distributions to our unitholders.

We also have many competitors in the midstream infrastructure business. Other companies offer similar third-party natural gas gathering, compression, processing and gas lift; crude oil gathering, stabilization, blending, storage and transporting; produced water gathering and disposal; and freshwater distribution services in our areas of operation. Some of our competitors for third-party volumes have greater financial resources and access to larger supplies of crude oil and natural gas than those available to us, which could allow those competitors to price their services more aggressively than we do. With respect to our produced water gathering and disposal and freshwater distribution operations, vehicle-based competition has the ability to expand to additional basins more quickly than pipeline-based assets and at a lower initial capital cost. In addition, many companies manage a portion of their own produced water internally without using a third-party provider, and some companies also compete with us by offering gathering and disposal to other oil and natural gas companies. Furthermore, technologies may be developed that could be used by our customers to recycle produced water and to recover oil through oilfield waste processing. Potential third-party customers regularly evaluate the best combination of value and price from competing alternatives and new technologies and, in the absence of a long-term contractual arrangement, can move between alternatives or, in some cases, develop their own alternatives with relative ease. This competition influences the prices we charge and requires us to control our costs aggressively and maximize efficiency in order to maintain acceptable operating margins; however, we may be unable to do so and remain competitive on a cost-for-service basis. In addition, existing and future competitors may develop or offer midstream infrastructure or new technologies that have pricing, location or other advantages over the gathering and disposal we provide, including a lower cost of capital.

If we are unable to make acquisitions on economically acceptable terms from Oasis or third parties, our future growth will be limited, and the acquisitions we do make may reduce, rather than increase, our distributable cash on a per unit basis.

Our ability to grow depends, in part, on our ability to make acquisitions that increase our distributable cash on a per unit basis. The acquisition component of our strategy is based, in large part, on our expectation of ongoing divestitures of assets by industry participants, including Oasis. Though our omnibus agreement will provide us with a ROFO with respect to the ROFO Assets, there is no guarantee that we will be able to make any such offer or consummate any acquisition of assets from Oasis. A material decrease in divestitures of assets from Oasis or otherwise would limit our opportunities for future acquisitions and could have a material adverse effect on our business, results of operations, financial condition and ability to make quarterly cash distributions to our unitholders.

 

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If we are unable to make accretive acquisitions from Oasis or third parties, whether because, among other reasons, (i) Oasis elects not to sell or contribute additional assets to us, (ii) we are unable to identify attractive third-party acquisition opportunities, (iii) we are unable to negotiate acceptable purchase contracts with Oasis or third parties, (iv) we are unable to obtain financing for these acquisitions on economically acceptable terms, (v) we are outbid by competitors or (vi) we are unable to obtain necessary governmental or third-party consents, then our future growth and ability to increase distributions will be limited. Furthermore, even if we do make acquisitions that we believe will be accretive, these acquisitions may nevertheless result in a decrease in our distributable cash on a per unit basis.

Any acquisition involves potential risks, including, among other things:

 

    mistaken assumptions about volumes, revenue and costs, including synergies and potential growth;

 

    an inability to secure adequate customer commitments to use the acquired systems or facilities;

 

    an inability to integrate successfully the assets or businesses we acquire;

 

    the assumption of unknown liabilities for which we are not indemnified or for which our indemnity is inadequate;

 

    limitations on rights to indemnity from the seller;

 

    mistaken assumptions about the overall costs of equity or debt;

 

    customer or key personnel losses at the acquired businesses;

 

    the diversion of management’s and employees’ attention from other business concerns; and

 

    unforeseen difficulties operating in new geographic areas or business lines.

If we are unable to make acquisitions from Oasis or third parties, our future growth and ability to increase distributions will be limited. Furthermore, if any acquisition eventually proves not to be accretive to our distributable cash on a per unit basis, it could have a material adverse effect on our business, results of operations, financial condition and ability to make quarterly cash distributions to our unitholders.

Our ability to grow in the future is dependent on our ability to access external financing for expansion capital expenditures.

We will distribute all of our available cash after expenses to our unitholders. We expect that we will rely upon external financing sources, including borrowings under our new revolving credit facility and the issuance of debt and equity securities, to fund expansion capital expenditures. However, we may not be able to obtain equity or debt financing on terms favorable to us, or at all. To the extent we are unable to efficiently finance growth externally, our cash distribution policy will significantly impair our ability to grow. In addition, because we distribute all of our available cash, we may not grow as quickly as businesses that reinvest their available cash to expand ongoing operations. Furthermore, Oasis is under no obligation to fund our growth. To the extent we issue additional units in connection with the financing of other expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no limitations in our partnership agreement on our ability to issue additional units, including units ranking senior to the common units. The incurrence of borrowings or other debt by us to finance our growth strategy would result in interest expense, which in turn would affect the available cash that we have to distribute to our unitholders.

Increased competition from other companies that provide midstream infrastructure could have a negative impact on the demand for our services, which could adversely affect our financial results.

Our ability to renew or replace existing contracts at rates sufficient to maintain current revenues and cash flows could be adversely affected by the activities of our competitors. Our midstream infrastructure assets compete primarily with other midstream infrastructure assets. Some of our competitors have greater financial

 

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resources and may now, or in the future, have access to greater supplies of crude oil, natural gas and/or produced water than we do or have greater capacity for crude oil and natural gas gathering, produced water gathering and disposal and freshwater distribution than we do. Some of these competitors may expand or construct assets that would create additional competition for the services we provide to our customers. In addition, our customers may develop their own midstream assets instead of using ours. Moreover, Oasis and its affiliates are not limited in their ability to compete with us. Please read “Conflicts of Interest and Fiduciary Duties.”

All of these competitive pressures could make it more difficult for us to retain our existing customers and/or attract new customers as we seek to expand our business, which could have a material adverse effect on our business, financial condition, results of operations and ability to make quarterly cash distributions to our unitholders. In addition, competition could intensify the negative impact of factors that decrease demand for oil and natural gas in the markets served by our assets, such as adverse economic conditions, weather, higher fuel costs and taxes or other governmental or regulatory actions that directly or indirectly increase the cost or limit the use of oil and natural gas.

We will be required to make substantial capital expenditures to increase our asset base. If we are unable to obtain needed capital or financing on satisfactory terms, our ability to make cash distributions may be diminished or our financial leverage could increase.

In order to increase our asset base, we will need to make expansion capital expenditures. If we do not make sufficient or effective expansion capital expenditures, we will be unable to expand our business operations and, as a result, we will be unable to raise the level of our future cash distributions. To fund our expansion capital expenditures and investment capital expenditures, we will be required to use cash from our operations or incur borrowings. Such uses of cash from our operations will reduce our distributable cash. Alternatively, we may sell additional common units or other securities to fund our capital expenditures.

Our ability to obtain bank financing to access the capital markets for future equity or debt offerings may be limited by our or Oasis’s financial condition at the time of any such financing or offering and the covenants in our existing debt agreements, as well as by general economic conditions, contingencies and uncertainties that are beyond our control. Even if we are successful in obtaining the necessary funds, the terms of such financings could limit our ability to pay distributions to our unitholders. In addition, incurring additional debt may significantly increase our interest expense and financial leverage, and issuing additional limited partner interests may result in significant unitholder dilution and would increase the aggregate amount of cash required to maintain the then-current distribution rate, which could materially decrease our ability to pay distributions at the prevailing distribution rate. None of our general partner, Oasis or any of their respective affiliates is committed to providing any direct or indirect support to fund our growth outside of the contractual commercial agreements to be entered into in connection with this offering.

The amount of capital expenditures that we make over time could increase as a result of increased demand for labor and materials.

A substantial majority of our capital expenditures in the near term are expected to be incurred as a result of the continued build-out of our assets. As such, the amount of capital expenditures that we incur over time will be impacted by the cost of labor and materials needed to construct our pipelines. Additionally, any delays in construction as a result of weather-related events or otherwise could increase our overall capital expenditure requirements.

 

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Oasis may suspend, reduce or terminate its obligations under our natural gas gathering, compression, processing and gas lift; crude oil gathering, stabilization, blending, storage and transporting; produced water gathering and disposal; and freshwater distribution agreements in certain circumstances, which could have a material adverse effect on our financial condition, results of operations, cash flows and ability to make distributions to our unitholders.

Our natural gas gathering, compression, processing and gas lift; crude oil gathering, stabilization, blending, storage and transporting; produced water gathering and disposal; and freshwater distribution agreements with Oasis will include provisions that permit Oasis to suspend, reduce or terminate its obligations under each agreement if certain events occur. These events include force majeure events that would prevent us from performing some or all of the required services under the applicable agreement. Oasis has the discretion to make such decisions notwithstanding the fact that they may significantly and adversely affect us. Any such reduction, suspension or termination of Oasis’s obligations would have a material adverse effect on our financial condition, results of operations, cash flows and ability to make distributions to our unitholders. Please read “Business—Contractual Arrangements with Oasis.”

The amount of our distributable cash depends primarily on our cash flow and not solely on profitability, which may prevent us from making distributions, even during periods in which we record net income.

The amount of our distributable cash depends primarily upon our cash flow and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record a net loss for financial accounting purposes, and conversely, we might fail to make cash distributions during periods when we record net income for financial accounting purposes.

Our utilization of existing capacity, expansion of existing midstream infrastructure assets and construction or purchase of new assets may not result in revenue increases and may be subject to regulatory, environmental, political, legal and economic risks, which could adversely affect our cash flows, results of operations and financial condition and, as a result, our ability to distribute cash to our unitholders.

The construction of additions or modifications to our existing systems and the construction or purchase of new assets involves numerous regulatory, environmental, political and legal uncertainties beyond our control and may require the expenditure of significant amounts of capital. Financing may not be available on economically acceptable terms or at all. If we undertake these projects, we may not be able to complete them on schedule, at the budgeted cost or at all. Moreover, our revenues may not increase immediately upon the expenditure of funds on a particular project. For example, we may construct facilities to capture anticipated future production growth in an area in which such growth does not materialize, or if we build a new facility the construction may occur over an extended period of time, and we may not receive any material increases in revenues until the project is completed. As a result, new gathering, disposal or other assets may not be able to attract enough throughput to achieve our expected investment return, which could adversely affect our results of operations and financial condition. In addition, the construction of additions to our existing assets may require us to obtain new rights-of-way prior to constructing new pipelines or facilities. We may be unable to timely obtain such rights-of-way to connect new supplies to our existing gathering pipelines or capitalize on other attractive expansion opportunities. Additionally, it may become more expensive for us to obtain new rights-of-way or to expand or renew existing rights-of-way. If the cost of renewing or obtaining new rights-of-way increases, our cash flows could be adversely affected.

Our business would be adversely affected if we, Oasis or our third-party customers experienced significant interruptions.

We depend upon the uninterrupted operations of our gathering system for the gathering of crude oil, natural gas and produced water , the disposal of produced water and the distribution of freshwater, as well as the need for collection of crude oil, natural gas and produced water produced by our customers, including Oasis and third parties. Any significant interruption at these assets or facilities would adversely affect our results of operations,

 

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cash flow and ability to make distributions to our unitholders. Operations at our midstream infrastructure assets and at the facilities owned or operated by our customers whom we rely upon for producing crude oil, natural gas and produced water could be partially or completely shut down, temporarily or permanently, as the result of any number of circumstances that are not within our control, such as:

 

    catastrophic events, including tornados, seismic activity such as earthquakes, lightning strikes, fires and floods;

 

    loss of electricity or power;

 

    rupture, spills or other unauthorized releases in or from gathering pipelines and disposal facilities;

 

    explosion, breakage, loss of power or accidents to machinery, storage tanks or facilities;

 

    leaks in packers and tubing below the surface, failures in cement or casing or ruptures in the pipes, valves, fittings, hoses, pumps, tanks, containment systems or houses that lead to spills or employee injuries;

 

    environmental remediation;

 

    pressure issues that limit or restrict our ability to inject water into the disposal well or limitations with the injection zone formation and its permeability or porosity that could limit or prevent disposal of additional fluids;

 

    labor difficulties;

 

    malfunctions in automated control systems at our assets or facilities;

 

    disruptions in the supply of produced water to our assets;

 

    failure of third-party pipelines, pumps, equipment or machinery; and

 

    governmental mandates, compliance, inspection, restrictions or laws and regulations.

In addition, there can be no assurance that we are adequately insured against such risks. As a result, our revenue and results of operations could be materially adversely affected.

If third-party pipelines or other facilities interconnected to our midstream systems become partially or fully unavailable, or if the volumes we gather or treat do not meet the quality requirements of such pipelines or facilities, our business, financial condition, results of operations, cash flows and ability to make distributions to our unitholders could be adversely affected.

Our midstream systems are connected to other pipelines or facilities, some of which are owned by third parties. The continuing operation of such third-party pipelines or facilities is not within our control. If any of these pipelines or facilities becomes unable to gather, transport, treat or process natural gas or crude oil, or if the volumes we gather or transport do not meet the quality requirements of such pipelines or facilities, our business, financial condition, results of operations, cash flows and ability to make distributions to our unitholders could be adversely affected.

Our exposure to commodity price risk may change over time and we cannot guarantee the terms of any existing or future agreements for our midstream services with third parties or with Oasis.

We currently generate the majority of our revenues pursuant to fee-based agreements under which we are paid based on volumetric fees, rather than the underlying value of the commodity. Consequently, our existing operations and cash flows have little direct exposure to commodity price risk. However, Oasis is exposed to commodity price risk, and extended reduction in commodity prices could reduce the future production volumes available for our midstream services below expected levels. Although we intend to maintain fee-based pricing terms on both new contracts and existing contracts for which prices have not yet been set, our efforts to negotiate such terms may not be successful, which could have a materially adverse effect on our business.

 

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Restrictions in our new revolving credit facility could adversely affect our business, financial condition, results of operations and ability to make quarterly cash distributions to our unitholders.

We expect to enter into a new revolving credit facility in connection with the closing of this offering. Our new revolving credit facility is expected to limit our ability to, among other things:

 

    incur or guarantee additional debt;

 

    redeem or repurchase units or make distributions under certain circumstances;

 

    make certain investments and acquisitions;

 

    incur certain liens or permit them to exist;

 

    enter into certain types of transactions with affiliates;

 

    merge or consolidate with another company; and

 

    transfer, sell or otherwise dispose of assets.

Our new revolving credit facility also is expected to contain covenants requiring us to maintain certain financial ratios and tests. Our ability to meet those financial ratios and tests can be affected by events beyond our control, and we cannot assure unitholders that we will meet any such ratios and tests.

The provisions of our new revolving credit facility may affect our ability to obtain future financing and pursue attractive business opportunities and our flexibility in planning for, and reacting to, changes in business conditions. In addition, a failure to comply with the provisions of our new revolving credit facility could result in a default or an event of default that could enable our lenders to declare the outstanding principal of that debt, together with accrued and unpaid interest, to be immediately due and payable. If the payment of our debt is accelerated, our assets may be insufficient to repay such debt in full, and our unitholders could experience a partial or total loss of their investment. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.”

Debt we incur in the future may limit our flexibility to obtain financing and to pursue other business opportunities.

Our future level of debt could have important consequences to us, including the following:

 

    our ability to obtain additional financing, if necessary, for working capital, capital expenditures (including required well pad connections and well connections pursuant to our produced water gathering and disposal agreement as well as acquisitions) or other purposes may be impaired or such financing may not be available on favorable terms;

 

    our funds available for operations, future business opportunities and distributions to unitholders will be reduced by that portion of our cash flow required to make interest payments on our debt;

 

    we may be more vulnerable to competitive pressures or a downturn in our business or the economy generally; and

 

    our flexibility in responding to changing business and economic conditions may be limited.

Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service any future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying our business activities, investments or capital expenditures, selling assets or issuing equity. We may not be able to affect any of these actions on satisfactory terms or at all.

 

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Increases in interest rates could adversely affect our business, our unit price and our ability to issue additional equity, to incur debt to capture growth opportunities or for other purposes, or to make cash distributions at our intended levels.

We will have significant exposure to increases in interest rates. After the consummation of this offering on a pro forma basis, we do not expect to have any outstanding indebtedness. However, in connection with the completion of this offering we expect to enter into a new revolving credit facility. As a result, our results of operations, cash flows and financial condition and, as a result, our ability to make cash distributions to our unitholders, could be materially adversely affected by significant increases in interest rates.

As with other yield-oriented securities, our unit price is impacted by the level of our cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank related yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our units, and a rising interest rate environment could have an adverse impact on our unit price and our ability to issue additional equity, to incur debt to expand or for other purposes, or to make cash distributions at our intended levels.

Our business could be adversely impacted if we are unable to obtain or maintain the regulatory permits required to develop and operate our facilities or to dispose of certain types of wastes.

We own and operate oil gathering and transportation lines, natural gas gathering lines, a natural gas processing facility and produced water gathering and disposal facilities in North Dakota and Montana. Each state has its own regulatory program for addressing the gathering, transporting, processing, handling, treatment, recycling or disposal of oil, natural gas and produced water , as applicable. We are also required to comply with federal laws and regulations governing our operations. These environmental and other laws and regulations require that, among other things, we obtain permits and authorizations prior to the development and operation of oil and natural gas gathering or transportation lines, natural gas processing facilities, waste treatment and storage facilities and in connection with the disposal and transportation of certain types of wastes. The applicable regulatory agencies strictly monitor waste handling and disposal practices at our facilities. For many of our sites, we are required under applicable laws, regulations and/or permits to conduct periodic monitoring, company-directed testing and third-party testing. Any failure to comply with such laws, regulations or permits may result in suspension or revocation of necessary permits and authorizations, civil or criminal liability and imposition of fines and penalties, which could adversely impact our operations and revenues and ability to continue to provide oil and natural gas gathering and transportation, natural gas processing and oilfield water services to our oil and natural gas E&P customers.

In addition, we may experience a delay in obtaining, be unable to obtain, or suffer the revocation of required permits or regulatory authorizations, which may cause us to be unable to serve customers, interrupt our operations and limit our growth and revenue. Regulatory agencies may impose more stringent or burdensome restrictions or obligations on our operations when we seek to renew or amend our permits. For example, permit conditions may limit the amount or types of wastes we may accept, require us to make material expenditures to upgrade our facilities, implement more burdensome and expensive monitoring or sampling programs, or increase the amount of financial assurance that we provide to cover future facility closure costs. Moreover, shareholder activists, nongovernmental organizations or the public may elect to protest the issuance or renewal of our permits on the basis of developmental, environmental or aesthetic considerations, which protests may contribute to a delay or denial in the issuance or reissuance of such permits.

Delays in obtaining permits by our oil and natural gas E&P customers for their operations could impair our business.

In most states, our oil and natural gas E&P customers are required to obtain permits from one or more governmental agencies in order to perform drilling and completion activities and to operate certain types of oilfield facilities. As with all governmental permitting processes, there is a degree of uncertainty as to whether a permit will be granted, the time it will take for a permit to be issued, and the conditions that may be imposed in

 

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connection with the granting of the permit. Some of our customers’ drilling and completion activities may take place on federal land or Native American lands, requiring leases and other approvals from the federal government or Native American tribes to conduct such drilling and completion activities. In some cases, federal agencies have cancelled proposed leases for federal lands and refused or delayed required approvals. Consequently, our customers’ operations in certain areas of the United States may be interrupted or suspended for varying lengths of time, resulting in reduced demand for our gathering, transportation, processing and/or disposal services and a corresponding loss of revenue to us as well as adversely affecting our results of operations in support of those customers.

In the future we may face increased obligations relating to the closing of our SWD facilities and may be required to provide an increased level of financial assurance to guaranty the appropriate closure activities occur for a SWD facility.

Obtaining a permit to own or operate SWD facilities generally requires us to establish performance bonds, letters of credit or other forms of financial assurance to address clean-up and closure obligations. As we acquire additional SWD facilities or expand our existing SWD facilities, these obligations will increase. Additionally, in the future, regulatory agencies may require us to increase the amount of our closure bonds at existing SWD facilities. We have accrued $1.7 million on our balance sheet related to our future closure obligations of our SWD facilities as of December 31, 2016. However, actual costs could exceed our current expectations, as a result of, among other things, federal, state or local government regulatory action, increased costs charged by service providers that assist in closing SWD facilities and additional environmental remediation requirements. The obligation to satisfy increased regulatory requirements associated with our SWD facilities could result in an increase of our operating costs and cause our available cash that we have to distribute to our unitholders to decline.

Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs of doing business and additional operations restrictions for our oil and natural gas E&P customers, which could reduce the throughput on our midstream infrastructure assets and adversely impact our revenues.

Hydraulic fracturing is an important and common well stimulation process that utilizes large volumes of water and sand, or other proppant, combined with fracturing chemical additives that are pumped at high pressure to crack open dense subsurface rock formations to release hydrocarbons. Our customers—primarily Oasis—regularly conduct hydraulic fracturing operations. Substantially all of Oasis’s oil and natural gas production is being developed from shale formations. These reservoirs require hydraulic fracturing completion processes to release the oil and natural gas from the rock so that it can flow through casing to the surface. Hydraulic fracturing is currently generally exempt from regulation under the United States Safe Drinking Water Act’s (“SDWA”) Underground Injection Control (“UIC”) program. In recent years, however, there has been increased public concern regarding an alleged potential for hydraulic fracturing to adversely affect drinking water supplies, and proposals have been made to enact separate federal, state and local legislation that would increase the regulatory burden imposed on hydraulic fracturing.

Hydraulic fracturing is typically regulated by state oil and natural gas commissions or similar agencies. However, several federal regulatory agencies have conducted investigations regarding, or asserted regulatory authority over, certain aspects of the process. For example, in December 2016, the U.S. Environmental Protection Agency (the “EPA”) released its final report on the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources under some circumstances. Additionally, in 2014, the EPA asserted regulatory authority pursuant to the SDWA over hydraulic fracturing activities involving the use of diesel and issued guidance covering such activities; in 2014, the EPA issued an Advance Notice of Proposed Rulemaking under Section 8 of the Toxic Substances Control Act to require reporting of the chemical substances and mixtures used in hydraulic fracturing; in 2016, the EPA published an effluent limit guideline final rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants;

 

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and, in 2015, the federal Bureau of Land Management (“BLM”) published a final rule that established new or more stringent standards relating to hydraulic fracturing on federal and American Indian lands, though this rule was struck down by a Wyoming federal judge in June 2016, was subsequently appealed by the EPA, and only recently, on March 15, 2017, was the subject of a BLM filing in the appeal seeking that the court hold the case in abeyance pending rescission of the rule. Also, from time to time, legislation has been introduced, but not enacted, in Congress to provide for federal regulation of hydraulic fracturing, including the underground disposal of fluids or propping agents associated with such fracturing activities and the disclosure of the chemicals used in the fracturing process.

Along with a number of other states, North Dakota and Montana, two states in which we operate, have adopted, and other states are considering adopting regulations that impose new or more stringent permitting, disclosure, disposal and well construction requirements on hydraulic fracturing operations. States could elect to prohibit high-volume hydraulic fracturing altogether, following the approach taken by the State of New York in 2015. Also, local governments may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular.

If new or more stringent laws or regulations relating to hydraulic fracturing are adopted at the federal, state or local levels, Oasis and our other third-party oil and natural gas producing customers’ fracturing activities could become subject to additional permit requirements, reporting requirements or operational restrictions and associated permitting delays or additional costs that could adversely affect the determination of whether a well is commercially viable. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that our customers are ultimately able to produce in commercial quantities. A reduction in production of oil and natural gas would likely reduce the demand for our gathering, transporting, processing and disposal services, which adversely impacts our revenues and profitability. Therefore, if these expenditures decline, our business is likely to be adversely affected.

Legislation or regulatory initiatives intended to address seismic activity could restrict our ability to dispose of produced water gathered from Oasis and our other third-party oil and natural gas producing customers, which could have a material adverse effect on our business.

We dispose of large volumes of produced water gathered from Oasis and our other third-party oil and natural gas producing customers produced in connection with their drilling and production operations pursuant to permits issued to us by governmental authorities overseeing such disposal activities. While these permits are issued pursuant to existing laws and regulations, these legal requirements are subject to change, which could result in the imposition of more stringent operating constraints or new monitoring and reporting requirements, owing to, among other things, concerns of the public or governmental authorities regarding such gathering or disposal activities.

For example, there exists a growing concern that the injection of produced water into belowground disposal wells triggers seismic activity in certain areas, including North Dakota and Montana, where we operate. In response to these concerns, federal and some state agencies are investigating whether such wells have caused increased seismic activity. Also, regulators in some states have adopted, and other states are considering adopting additional requirements related to seismic safety, including the permitting of SWD wells or otherwise to assess any relationship between seismicity and the use of such wells, which has resulted in some states restricting, suspending or shutting down the use of such injection wells. The adoption and implementation of any new laws or regulations that restrict our ability to dispose of produced water gathered from Oasis and our other third-party oil and natural gas producing customers, by limiting volumes, disposal rates, disposal well locations or otherwise, or requiring us to shut down disposal wells, could have a material adverse effect on our business, financial condition and results of operations.

 

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Compliance with environmental laws and regulations could cause us and our oil and natural gas E&P customers to incur significant costs or liabilities as well as delays in our customers’ production of oil and natural gas that could reduce our volume of services and have a material adverse effect on our business.

Our oil gathering and transportation, natural gas gathering and processing, and produced water gathering and disposal services as well as related oilfield operations are subject to stringent federal, state and local laws and regulations governing the handling, disposal and discharge of materials and wastes and the protection of natural resources and the environment. Numerous governmental authorities, such as the EPA and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly response actions. These laws and regulations may impose numerous obligations that are applicable to our and our oil and natural gas E&P customers’ operations, including the acquisition of permits to conduct regulated activities, the incurrence of capital or operating expenditures to limit or prevent releases of materials from our or our customers’ operations, the prohibition of noise-producing activities, the limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands and other protected areas and the imposition of substantial liabilities and remedial obligations for pollution or contamination resulting from our and our customers’ operations. Compliance with environmental laws and regulations is difficult and may require us to make significant expenditures. Failure to comply with these laws, regulations and permits may result in the assessment of sanctions, including administrative, civil and criminal penalties, the imposition of investigatory, remedial and corrective action obligations or the incurrence of capital expenditures, and the issuance of injunctions limiting or preventing some or all of our operations in a particular area. Private parties, including the owners of the properties through which our gathering line assets pass or our processing plant is located, properties we formerly operated, and facilities where wastes resulting from our operations are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance and require the cleanup of any contamination, as well as to seek damages for non-compliance with environmental laws, regulations and permits or for personal injury or property damage. We may not be able to recover all or any of these costs from insurance. We may also experience a delay in obtaining or be unable to obtain required permits, which may cause us to lose potential and current customers, interrupt our operations and limit our growth and revenues, which in turn could affect our profitability. In addition, our customers’ liability under, or costs and expenditures to comply with, environmental laws and regulations could lead to delays and increased operating costs, which could reduce the volumes of oil and natural gas that move through our gathering line assets or processing plant.

Our operations also pose risks of environmental liability due to spills or other releases from our operations to surface or subsurface soils, surface water or groundwater. Certain environmental laws impose strict as well as joint and several liability for costs required to remediate and restore sites where hydrocarbons, materials or wastes have been stored or released. We may be required to remediate contaminated properties currently or formerly operated by us or facilities of third parties that received waste generated by our operations regardless of whether such contamination resulted from the conduct of others or from consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. In connection with certain acquisitions, we could assume, or be required to provide indemnification against, environmental liabilities that could expose us to material losses. In addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and safety impacts of our operations. Moreover, public interest in the protection of the environment has increased dramatically in recent years. The trend of more expansive and stringent environmental legislation and regulations applied to the oil and natural gas industry could continue, resulting in material increases in our costs of doing business and consequently affecting profitability.

Changes in environmental laws and regulations occur frequently, and compliance with more stringent requirements may increase the costs to our customers of developing and producing petroleum hydrocarbons, which could lead to reduced operations by these customers and, as a result, may have an indirect and adverse effect on the amount of customer-produced oil or natural gas gathered, transported or processed by us or produced water delivered to our facilities by our customers, which could have a material adverse effect on our

 

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financial condition and results of operations. Please read “Business—Environmental and Occupational Health and Safety Matters” for more information.

Climate change laws and regulations restricting emissions of greenhouse gases (“GHGs”) could result in increased operating costs and reduced demand for the oil and natural gas that we handle, while potential physical effects of climate change could disrupt our operations and cause us to incur significant costs in preparing for or responding to those effects.

Climate change continues to attract considerable public and scientific attention. As a result, numerous proposals have been made and are likely to continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of GHGs. These efforts have included consideration by states or groupings of states of cap-and-trade programs, carbon taxes, GHG reporting and tracking programs, and regulations that directly limit GHG emissions from certain sources.

At the federal level, no comprehensive climate change legislation has been implemented to date. However, the EPA has determined that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment and has adopted regulations under existing provisions of the federal Clean Air Act (“CAA”) that establish Prevention of Significant Deterioration (“PSD”) construction and Title V operating permit reviews for GHG emissions from certain large stationary sources that already are potential major sources of certain principal, or criteria, pollutant emissions. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards. The EPA has also adopted rules requiring the monitoring and reporting of GHG emissions from specified sources in the United States on an annual basis, including, among others, oil and natural gas production, processing, transmission and storage facilities.

Federal agencies also have begun directly regulating emissions of methane, a GHG, from oil and natural gas operations. In June 2016, the EPA published New Source Performance Standards (“NSPS”), known as Subpart OOOOa, that require certain new, modified or reconstructed facilities in the oil and natural gas sector to reduce these methane gas and volatile organic compound emissions. These Subpart OOOOa standards will expand the previously issued NSPS Subpart OOOO requirements issued in 2012 by using certain equipment-specific emissions control practices. Several states and industry groups have filed suit before the D.C. Circuit challenging EPA’s implementation of the methane rule and legal authority to issue the methane rules. Moreover, in November 2016, the EPA issued a final Information Collection Request (“ICR”) seeking information about methane emissions from facilities and operations in the oil and natural gas industry, but on March 2, 2017, the EPA announced that it was withdrawing the ICR so that the agency could further assess the need for the information that it was collecting through the request. Additionally, in December 2015, the United States joined the international community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France to prepare an agreement requiring member countries to review and “represent a progression” in their intended nationally determined contributions, which will set GHG emission reduction goals every five years beginning in 2020. This “Paris Agreement” was signed by the United States in April 2016 and entered into force in November 2016, but it does not create any binding obligations for nations to limit their GHG emissions; rather, the agreement includes pledges to voluntarily limit or reduce future emissions. With the change in Presidential Administrations, future participation in this agreement by the United States remains uncertain.

The adoption and implementation of any international, federal or state legislation, regulations or other regulatory initiatives that require reporting of GHGs or otherwise restricts emissions of GHGs from our or our oil and natural gas E&P customers’ equipment and operations could require us and our customers to incur increased costs, adversely affect demand for the oil and natural gas we handle or produced water we gather and dispose of and thus have a material adverse effect on our business, financial condition and results of operations. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events. If such effects were to occur, they could have an adverse

 

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effect on our operations. At this time, we have not developed a comprehensive plan to address the legal, economic, social or physical impacts of climate change on our operations.

The rates of our regulated assets are subject to review and reporting by federal regulators, which could adversely affect our revenues.

Currently, only the crude oil transportation system connecting the Wild Basin area to the Johnson’s Corner market center transports crude oil in interstate commerce. Pipelines that transport crude oil in interstate commerce are, among other things, subject to rate regulation by the Federal Energy Regulatory Commission, or FERC, unless such rate requirements are waived. FERC regulates interstate transportation of crude oil under the Interstate Commerce Act of 1887 as modified by the Elkins Act (“ICA”), the Energy Policy Act of 1992 (“EPAct”) and the rules and regulations promulgated under those laws. FERC regulations require that rates and terms and conditions of service for interstate service pipelines that transport crude oil be just and reasonable and must not be unduly discriminatory or confer any undue preference upon any shipper. FERC’s regulations also require interstate pipelines to file with FERC and publicly post tariffs stating their interstate transportation rates and terms and conditions of service.

Under the ICA, FERC or interested persons may challenge existing or proposed new or changed rates, services, or terms and conditions of service. Under certain circumstances, FERC could limit a regulated pipeline’s ability to charge rates until completion of an investigation during which FERC could find that the new or changed rate is unlawful. In contrast, FERC has clarified that initial rates and terms of service agreed upon with committed shippers in a transportation services agreement are not subject to protest or a cost-of-service analysis where the pipeline held an open season offering all potential shippers service on the same terms.

A successful rate challenge could result in a regulated pipeline paying refunds of revenue collected in excess of the just and reasonable rate, together with interest for the period that the rate was in effect, if any. FERC may also order a pipeline to reduce its rates prospectively, and may require a regulated pipeline to pay shippers reparations retroactively for rate overages for a period of up to two years prior to the filing of a complaint. FERC also has the authority to change terms and conditions of service if it determines that they are unjust or unreasonable or unduly discriminatory or preferential. We may also be required to respond to requests for information from government agencies, including compliance audits conducted by FERC.

FERC’s ratemaking policies are subject to change and may impact the rates charged and revenues received from the operation of our crude oil gathering system in the Wild Basin area and any other natural gas or liquids pipeline that is determined to be under the jurisdiction of FERC. In 2005, FERC issued a policy statement stating that it would permit common carrier pipelines, among others, to include an income tax allowance in cost-of-service rates to reflect actual or potential tax liability attributable to a regulated entity’s operating income, regardless of the form of ownership. On December 15, 2016, FERC issued a Notice of Inquiry requesting energy industry input on how FERC should address income tax allowances in cost-based rates proposed by pipeline companies organized as part of a master limited partnership. FERC’s current policy permits pipelines and storage companies to include a tax allowance in the cost-of-service used as the basis for calculating their regulated rates. For pipelines and storage companies owned by partnerships or limited liability company interests, the current tax allowance policy reflects the actual or potential income tax liability on the FERC jurisdictional income attributable to all partnership or limited liability company interests if the ultimate owner of the interest has an actual or potential income tax liability on such income. FERC issued the Notice of Inquiry in response to a remand from the United States Court of Appeals for the D.C. Circuit in United Airlines, Inc., et al. v. FERC, finding that FERC had acted arbitrarily and capriciously when it failed to demonstrate that permitting an interstate petroleum products pipeline organized as a limited partnership to include an income tax allowance in the cost of service underlying its rates in addition to the discounted cash flow return on equity would not result in the pipeline partnership owners double-recovering their income taxes. We cannot predict whether FERC will successfully justify its conclusion that there is no double recovery of taxes under these circumstances or whether FERC will modify its current policy on either income tax allowances or return on equity calculations for pipeline companies organized as part of a master limited partnership. However, any modification that reduces or

 

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eliminates an income tax allowance for pipeline companies organized as a part of a master limited partnership or decreases the return on equity for such pipelines could result in an adverse impact on our revenues associated with the transportation services we provide pursuant to cost-based rates.

Failure to comply with applicable market behavior rules, regulations and orders could subject us to substantial penalties and fines.

In August 2005, Congress enacted the Energy Policy Act of 2005 (the “EPAct 2005”). Among other matters, the EPAct 2005 amended the Natural Gas Act of 1938 (the “NGA”) to add an anti-manipulation provision that makes it unlawful for “any entity” to engage in prohibited behavior in contravention of rules and regulations to be prescribed by FERC and, furthermore, provides FERC with additional civil penalty authority. In January 2006, FERC issued Order No. 670, a rule implementing the anti-manipulation provisions of the EPAct 2005. The rules make it unlawful for any entity, directly or indirectly, in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC or the purchase or sale of transportation services subject to the jurisdiction of FERC to (1) use or employ any device, scheme or artifice to defraud; (2) to make any untrue statement of material fact or omit to make any such statement necessary to make the statements not misleading; or (3) to engage in any act or practice that operates as a fraud or deceit upon any person. Such anti-manipulation rules apply to interstate gas pipelines and storage companies and intrastate gas pipelines and storage companies that provide interstate services, such as Natural Gas Policy Act (“NGPA”) Section 311 service, as well as otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC’s jurisdiction. The anti-manipulation rules do not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering to the extent such transactions do not have a “nexus” to jurisdictional transactions. The EPAct 2005 also amended the NGA and the NGPA to give FERC authority to impose civil penalties for violations of these statutes and FERC’s regulations, rules and orders, up to $1,000,000 per violation per day for violations occurring after August 8, 2005. In July 2016, FERC increased that maximum penalty to $1,193,970 per violation per day to account for inflation. In connection with this enhanced civil penalty authority, FERC issued a revised policy statement on enforcement to provide guidance regarding the enforcement of the statutes, orders, rules and regulations it administers, including factors to be considered in determining the appropriate enforcement action to be taken. In addition, the Commodities Futures Trading Commission (the “CFTC”) is directed under the Commodities Exchange Act (the “CEA”) to prevent price manipulations for the commodity and futures markets, including the energy futures markets. Pursuant to the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) and other authority, the CFTC has adopted anti-market manipulation regulations that prohibit fraud and price manipulation in the commodity and futures markets. The CFTC also has statutory authority to seek civil penalties of up to the greater of $1,000,000 or triple the monetary gain to the violator for violations of the anti-market manipulation sections of the CEA. Should we fail to comply with all applicable FERC, CFTC or other statutes, rules, regulations and orders governing market behavior, we could be subject to substantial penalties and fines.

A change in the jurisdictional characterization of some of our assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of our assets, which may cause our operating expenses to increase, limit the rates we charge for certain services and decrease the amount of our distributable cash.

Although FERC has not made a formal determination with respect to the facilities we consider to be natural gas gathering pipelines, we believe that our natural gas gathering pipelines meet the traditional tests that FERC has used to determine that a pipeline is a gathering pipeline and is therefore not subject to FERC jurisdiction. The distinction between FERC-regulated transmission services and federally unregulated gathering services, however, has been the subject of substantial litigation, and FERC determines whether facilities are gathering facilities on a case-by-case basis, so the classification and regulation of our gathering facilities is subject to change based on future determinations by FERC, the courts or Congress. If FERC were to consider the status of an individual facility and determine that the facility or services provided by it are not exempt from FERC regulation under the NGA and that the facility provides interstate service, the rates for, and terms and conditions of, services provided by such facility would be subject to regulation by FERC under the NGA or the NGPA.

 

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Such regulation could decrease revenue, increase operating costs and, depending upon the facility in question, adversely affect our results of operations and cash flows. In addition, if any of our facilities were found to have provided services or otherwise operated in violation of the NGA or NGPA, this could result in the imposition of substantial civil penalties, as well as a requirement to disgorge revenues collected for such services in excess of the maximum rates established by FERC.

Our natural gas gathering pipelines are exempt from the jurisdiction of FERC under the NGA, but FERC regulation may indirectly impact gathering services. FERC’s policies and practices across the range of its crude oil and natural gas regulatory activities, including, for example, its policies on interstate open access transportation, ratemaking, capacity release, and market center promotion, may indirectly affect intrastate markets. In recent years, FERC has pursued pro-competitive policies in its regulation of interstate crude oil and natural gas pipelines. However, we cannot assure you that FERC will continue to pursue this approach as it considers matters such as pipeline rates and rules and policies that may indirectly affect our natural gas gathering services.

Natural gas gathering may receive greater regulatory scrutiny at the state level; therefore, our natural gas gathering operations could be adversely affected should they become subject to the application of state regulation of rates and services. Our gathering operations could also be subject to safety and operational regulations relating to the design, construction, testing, operation, replacement and maintenance of gathering facilities. We cannot predict what effect, if any, such changes might have on our operations, but we could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.

In addition, certain of our crude oil gathering pipelines do not provide interstate services and therefore are not subject to regulation by FERC pursuant to the ICA. The distinction between FERC-regulated interstate pipeline transportation, on the one hand, and intrastate pipeline transportation, on the other hand, also is a fact-based determination. The classification and regulation of these crude oil gathering pipelines are subject to change based on future determinations by FERC, federal courts, Congress or by regulatory commissions, courts or legislatures in the states in which our crude oil gathering pipelines are located. We cannot provide assurance that FERC will not in the future, either at the request of other entities or on its own initiative, determine that some or all of our gathering pipeline systems and the services we provide on those systems are within FERC’s jurisdiction. If it was determined that more or all of our crude oil gathering pipeline systems are subject to FERC’s jurisdiction under the ICA, and are not otherwise exempt from any applicable regulatory requirements, the imposition of possible cost-of service rates and common carrier requirements on those systems could adversely affect the results of our operations on those systems.

We must comply with occupational health and safety laws and regulations at our facilities and in connection with our operations and failure to do so could result in significant liability and/or fines and penalties.

We are subject to a wide range of national, state and local occupational health and safety laws and regulations that impose specific standards addressing worker health and safety matters. Regulations implementing these health and safety laws are adopted and enforced by the federal Occupational Safety and Health Administration (“OSHA”) and analogous state agencies whose purpose is to protect the health and safety of workers. In addition, the OSHA hazard communication standard, the Emergency Planning and Community Right-to-Know Act and comparable state statutes and any implementing regulations require that we maintain, organize and/or disclose information about hazardous materials used or produced in our operations and that this information be provided to employees, state and local governmental authorities and citizens. In December 2015, the U.S. Departments of Justice and Labor announced a plan to more frequently and effectively prosecute worker health and safety violations, including enhanced penalties. These legal requirements are subject to change, as are the enforcement priorities of OSHA and the analogous state agencies. Failure to comply with these health and safety laws and regulations could lead to third-party claims, criminal and regulatory violations, civil fines and changes in the way we operate our facilities, each of which could increase the cost of operating our business and

 

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have a material adverse effect on our financial position, results of operations and cash flows and our ability to make cash distributions to our unitholders.

Our business involves many hazards and operational risks, some of which may not be fully covered by insurance. The occurrence of a significant accident or other event that is not fully insured could curtail our operations and have a material adverse effect on our ability to distribute cash and, accordingly, the market price for our common units.

Our operations are subject to all of the hazards inherent in the lines of business we participate in, including:

 

    damages to pipelines, terminals and facilities, related equipment and surrounding properties caused by earthquakes, tornados, floods, fires, severe weather, explosions and other natural disasters and acts of terrorism or vandalism;

 

    maintenance, repairs, mechanical or structural failures at our or Oasis’s facilities or at third-party facilities on which our or Oasis’s operations are dependent, including electrical shortages, power disruptions and power grid failures;

 

    equipment defects, vehicle accidents, blowouts, surface cratering, uncontrollable flows of natural gas or well fluids, abnormally pressured formations and various environmental hazards such as unauthorized oil spills and releases of, and exposure to, hazardous substances;

 

    risks associated with hydraulic fracturing, including any mishandling, surface spillage or potential underground migration of fracturing fluids, including chemical additives;

 

    damages to and loss of availability of interconnecting third-party pipelines, railroads, terminals and other means of delivering produced water, freshwater, oil and natural gas;

 

    crude oil tank car derailments, fires, explosions and spills;

 

    disruption or failure of information technology systems and network infrastructure due to various causes, including unauthorized access or attack;

 

    curtailments of operations due to severe seasonal weather;

 

    riots, strikes, lockouts or other industrial disturbances;

 

    governmental mandates, compliance, inspections restrictions or laws and regulations; and

 

    other hazards.

Any of these risks could adversely affect our ability to conduct operations or result in substantial loss to us as a result of claims for:

 

    injury or loss of life;

 

    damage to and destruction of property, natural resources and equipment;

 

    pollution and other environmental damage;

 

    regulatory investigations and penalties;

 

    suspension of our operations; and

 

    repair and remediation costs.

We may elect not to obtain insurance for any or all of these risks if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. The occurrence of an event that is not fully covered by insurance could have a material adverse effect on our business, financial condition and results of operations.

 

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Federal and state legislative and regulatory initiatives relating to pipeline safety that require the use of new or more stringent safety controls, substantial changes to existing integrity management programs, or more stringent enforcement of applicable legal requirements could subject us to increased capital and operating costs and operational delays.

Certain of our pipelines are subject to regulation by Pipeline and Hazardous Materials Safety Administration (“PHMSA”) under the Hazardous Liquid Pipeline Safety Act (“HLPSA”) with respect to oil and the Natural Gas Pipeline Safety Act (“NGPSA”) with respect to natural gas. The HLPSA and NGPSA govern the design, installation, testing, construction, operation, replacement and management of oil and natural gas pipeline facilities. These laws have resulted in the adoption of rules by PHMSA, that, among other things, require transportation pipeline operators to implement integrity management programs, including more frequent inspections, correction of identified anomalies and other measures to ensure pipeline safety in High Consequence Areas (“HCAs”), such as high population areas, areas unusually sensitive to environmental damage and commercially navigable waterways. In addition, states have adopted regulations similar to existing PHMSA regulations for certain intrastate natural gas and hazardous liquid pipelines, which regulations may impose more stringent requirements than found under federal law. Historically, our pipeline safety compliance costs have not had a material adverse effect on our results of operations; however, there can be no assurance that such costs will not be material in the future or that such future compliance costs will not have a material adverse effect on our business and operating results. New laws or regulations adopted by PHMSA may impose more stringent requirements applicable to integrity management programs and other pipeline safety aspects of our operations, which could cause us to incur increased capital and operating costs and operational delays.

The HLPSA and NGPSA were amended by the 2011 Pipeline Safety Act which became law in January 2012. The 2011 Act increased the penalties for safety violations, established additional safety requirements for newly constructed pipelines and required studies of safety issues that could result in the adoption of new regulatory requirements by PHMSA for existing pipelines. More recently, in June 2016, the 2016 Pipeline Safety Act was passed, extending PHMSA’s statutory mandate through 2019 and, among other things, requiring PHMSA to complete certain of its outstanding mandates under the 2011 Pipeline Safety Act and developing new safety standards for natural gas storage facilities by June 22, 2018. The 2016 Act also empowers PHMSA to address imminent hazards by imposing emergency restrictions, prohibitions and safety measures on owners and operators of hazardous liquid or natural gas pipeline facilities without prior notice or an opportunity for a hearing. PHMSA issued interim regulations in October 2016 to implement the agency’s expanded authority to address unsafe pipeline conditions or practices that pose an imminent hazard to life, property, or the environment.

The adoption of new or amended regulations by PHMSA that result in more stringent or costly pipeline integrity management or safety standards could have a significant adverse effect on our results of operations. For example, in January 2017, PHMSA issued a final rule that significantly extends and expands the reach of certain agency integrity management requirements, such as, for example, periodic assessments, leak detection and repairs, regardless of the pipeline’s proximity to a high consequence area. The final rule also imposes new reporting requirements for certain unregulated pipelines, including all hazardous liquid gathering lines. However, the implementation of this final rule by publication in the Federal Register is uncertain given the recent change in Presidential Administrations. In a second example, in March 2016, PHMSA announced a proposed rulemaking that would impose new or more stringent requirements for certain natural gas lines and gathering lines including, among other things, expanding certain of PHMSA’s current regulatory safety programs for natural gas pipelines in newly defined “moderate consequence areas” that contain as few as 5 dwellings within a potential impact area; requiring natural gas pipelines installed before 1970 and thus excluded from certain pressure testing obligations to be tested to determine their maximum allowable operating pressures (“MAOP”); and requiring certain onshore and offshore gathering lines in Class I areas to comply with damage prevention, corrosion control, public education, MAOP limits, line markers and emergency planning standards. Additional requirements proposed by this proposed rulemaking would increase PHMSA’s integrity management requirements for natural gas pipelines and also require consideration of seismicity in evaluating threats to pipelines. New laws or regulations adopted

 

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by PHMSA may impose more stringent requirements applicable to integrity management programs and other pipeline safety aspects of our operations, which could cause us to incur increased capital and operating costs and operational delays. In the absence of the PHMSA pursuing any legal requirements, state agencies, to the extent authorized, may pursue state standards, including standards for rural gathering lines.

We do not own all of the land on which our facilities are located, which could result in disruptions to our operations.

We do not own all of the land on which our facilities have been constructed, and we are, therefore, subject to the possibility of more onerous terms or increased costs to retain necessary land use if we do not have valid rights-of-way or if such rights-of-way lapse or terminate. We obtain the rights to construct and operate our assets on land owned by third parties and governmental agencies for a specific period of time. Our loss of these rights, through our inability to renew right-of-way contracts or otherwise, could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to you.

A shortage of equipment and skilled labor could reduce equipment availability and labor productivity and increase labor and equipment costs, which could have a material adverse effect on our business and results of operations.

Midstream infrastructure assets require special equipment and laborers skilled in multiple disciplines, such as equipment operators, mechanics and engineers, among others. If we experience shortages of necessary equipment or skilled labor in the future, our labor and equipment costs and overall productivity could be materially and adversely affected. If our equipment or labor prices increase or if we experience materially increased health and benefit costs for employees, our results of operations could be materially and adversely affected.

The loss of key personnel could adversely affect our ability to operate.

We depend on the services of a relatively small group of our general partner’s and Oasis’s senior management and technical personnel. We do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals. Because competition for experienced personnel in the industry is intense, we may not be able to find acceptable replacements with comparable skills and experience. The loss of the services of our general partner’s senior management or technical personnel could have a material adverse effect on our business, financial condition and results of operations.

We do not have any officers or employees apart from those seconded to us and rely solely on officers of our general partner and employees of Oasis pursuant to our Services and Secondment Agreement with Oasis.

We are managed and operated by the board of directors of our general partner. Affiliates of Oasis conduct businesses and activities of their own in which we have no economic interest. As a result, there could be material competition for the time and effort of the officers and employees who provide services to our general partner and Oasis. If our general partner and the officers and employees of Oasis do not devote sufficient attention to the management and operation of our business, our financial results may suffer, and our ability to make distributions to our unitholders may be reduced. For additional information, please read “Certain Relationships and Related Party Transactions—Agreements with Affiliates in Connection with the Transactions—Services and Secondment Agreement.”

 

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Oil and natural gas producers’ operations, especially those using hydraulic fracturing, are substantially dependent on the availability of water. Restrictions on the ability to obtain water may incentivize water recycling efforts by our customers, which would decrease the volume of non-hazardous waste and water delivered to our facilities and could have an adverse effect on our cash flows.

Water is an essential component of oil and natural gas production during both the drilling and hydraulic fracturing processes. However, the availability of suitable water supplies may be limited by prolonged drought conditions and changing laws and regulations relating to water use and conservation. For example, in North Dakota, the Missouri River has been a preferred source for water used in hydraulic fracturing operations occurring in the state. However, in recent years, the U.S. Army Corps of Engineers, or Corps, has restricted access to the Missouri River within certain reservoirs along Lake Sakakawea and Lake Oahe. In 2010, the Corps placed a moratorium on issuing new real estate permits, which in turn blocked any new industrial water intakes, around Lake Sakakawea. In February 2013, the Corps lifted the moratorium, but the issuance of water easements and access may continue to be restricted by the Corps. Drought conditions, in conjunction with restricted access to waters of the Missouri River by the Corps, may result in increased operating costs, as industrial water users may be required to haul available water over longer distances. The occurrence of any one or more of these developments may result in reduced operations by our oil and natural gas producing customers, which could result in decreased volumes of return flow water being delivered to our facilities.

Our customers must comply with North Dakota rules on the capture rather than flaring of natural gas in connection with production of oil and natural gas, which compliance activities may increase the costs of compliance and restrict or prohibit future production, which results could adversely affect our services.

On July 1, 2014, the North Dakota Industrial Commission adopted Order No. 24665 (“July 2014 Order”) pursuant to which the agency adopted legally enforceable “gas capture percentage goals” targeting the capture of 74% of natural gas produced in the State by October 1, 2014, 77% percent of such natural gas by January 1, 2015, 85% of such natural gas by January 1, 2016 and 90% of such natural gas by October 1, 2020. Modification of the July 2014 Order was announced by the NDIC in the fourth quarter of 2015, resulting in the existing January 1, 2015 gas capture rate of 77% being extended to April 1, 2016 and updated gas capture rates of 80% by April 1, 2016, 85% by November 1, 2016, 88% by November 1, 2018 and 91% by November 1, 2020. The July 2014 Order establishes an enforcement mechanism for policy recommendations that were previously adopted by the North Dakota Industrial Commission in March 2014. Those recommendations required all E&P operators applying for new drilling permits in the state after June 1, 2014 to develop Gas Capture Plans that provide measures for reducing the amount of natural gas flared by those operators so as to be consistent with the agency’s now-implemented gas capture percentage goals. In particular, the July 2014 Order provides that after an initial 90-day period, wells must meet or exceed the North Dakota Industrial Commission’s gas capture percentage goals on a per-well, per-field, county, or statewide basis. Failure to comply with the gas capture percentage goals will result in an operator having to restrict its production to 200 Bopd if at least 60% of the monthly volume of associated natural gas produced from the well is captured, or 100 Bopd if less than 60% of such monthly volume of natural gas is captured. To the extent that our customers cannot comply with these gas capture requirements, such requirements could result in increased compliance costs to such customers or restrictions on future production, which events could have an adverse effect on the services we provide.

Oil and natural gas prices are volatile, and a change in these prices in absolute terms, or an adverse change in the prices of oil and natural gas relative to one another, could adversely affect our gross margin, business, financial condition, results of operations, cash flows and ability to make cash distributions.

We are subject to risks due to frequent and often substantial fluctuations in commodity prices. In the past, the prices of oil and natural gas and other commodities have been extremely volatile, and we expect this volatility to continue. Our future cash flow may be materially adversely affected if commodity markets experience significant, prolonged pricing deterioration.

 

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The markets for and prices of oil and natural gas and other commodities depend on factors that are beyond our control. These factors include the supply of and demand for these commodities, which fluctuate with changes in market and economic conditions and other factors, including:

 

    the levels of domestic production and consumer demand;

 

    the availability of transportation systems with adequate capacity;

 

    the volatility and uncertainty of regional pricing differentials;

 

    worldwide economic conditions;

 

    worldwide political events, including actions taken by foreign oil and natural gas producing nations;

 

    worldwide weather events and conditions, including natural disasters and seasonal changes;

 

    the price and availability of alternative fuels;

 

    the effect of energy conservation measures;

 

    the nature and extent of governmental regulation (including environmental requirements) and taxation;

 

    fluctuations in demand from electric power generators and industrial customers; and

 

    the anticipated future prices of oil and natural gas, condensate and other commodities.

We may not be able to renew or replace expiring contracts at favorable rates or on a long-term basis.

We gather the oil and natural gas through our midstream systems under long-term contracts with Oasis. As these contracts expire, we may have to negotiate extensions or renewals with Oasis or enter into new contracts with other suppliers and customers. We may be unable to obtain new contracts on favorable commercial terms, if at all. We also may be unable to maintain the economic structure of a particular contract with Oasis or the overall mix of our contract portfolio. Moreover, we may be unable to obtain areas of mutual interest from new customers in the future, and we may be unable to renew existing areas of mutual interest with current customers as and when they expire. The extension or replacement of existing contracts depends on a number of factors beyond our control, including:

 

    the level of existing and new competition to provide gathering services to our markets;

 

    the macroeconomic factors affecting natural gas gathering economics for our current and potential customers;

 

    the balance of supply and demand, on a short-term, seasonal and long-term basis, in our markets;

 

    the extent to which the customers in our markets are willing to contract on a long-term basis; and

 

    the effects of federal, state or local regulations on the contracting practices of our customers.

To the extent we are unable to renew our existing contracts on terms that are favorable to us or successfully manage our overall contract mix over time, our revenues and cash flows could decline and our ability to make distributions to our unitholders could be materially and adversely affected.

Contracts with customers are subject to additional risk in the event of a bankruptcy proceeding.

To the extent any of our customers is in financial distress or commences bankruptcy proceedings, our contracts with them, including provisions relating to dedications of production, may be subject to renegotiation or rejection under applicable provisions of the United States Bankruptcy Code. If a contract with a customer is altered or rejected in bankruptcy proceedings, we could lose some or all of the expected revenues associated with that contract, which could cause the market price of our common units to decline.

 

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Our businesses and results of operations are subject to seasonal fluctuations, which could result in fluctuations in our operating results and common unit price.

Our business is subject to seasonal fluctuations. Demand for natural gas generally decreases during the spring and fall months and increases during the summer and winter months. Severe or prolonged winters may, however, impact our ability to complete additional well connections or complete construction projects, which may impact the rate of our growth. Severe winter weather may also impact or slow the ability of our customers to execute their planned drilling and development plans. In addition, the volumes of condensate produced at our processing facilities fluctuate seasonally, with volumes generally increasing in the winter months and decreasing in the summer months as a result of the physical properties of natural gas and comingled liquids. Severe or prolonged summers may adversely affect our results of operations.

Crude oil and natural gas production and gathering may be adversely affected by weather conditions and terrain, which in turn could negatively impact the operations of our gathering, treating and processing facilities and our construction of additional facilities.

Extended periods of below freezing weather and unseasonably wet weather conditions, especially in North Dakota and Montana, can be severe and can adversely affect crude oil and natural gas operations due to the potential shut-in of producing wells or decreased drilling activities. The result of these types of interruptions could result in a decrease in the volumes supplied to our midstream systems. Further, delays and shutdowns caused by severe weather may have a material negative impact on the continuous operations of our gathering, treating, processing and disposal systems, including interruptions in service. These types of interruptions could negatively impact our ability to meet our contractual obligations to our customers and thereby give rise to certain termination rights and/or the release of dedicated acreage. Any resulting terminations or releases could materially adversely affect our business and results of operations.

We also may be required to incur additional costs and expenses in connection with the design and installation of our facilities due to their location and surrounding terrain. We may be required to install additional facilities, incur additional capital and operating expenditures, or experience interruptions in or impairments of our operations to the extent that the facilities are not designed or installed correctly. If such facilities are not designed or installed correctly, do not perform as intended, or fail, we may be required to incur significant capital expenditures to correct or repair the deficiencies, or may incur significant damages to or loss of facilities, and our operations may be interrupted as a result of deficiencies or failures. In addition, such deficiencies may cause damage to the surrounding environment, including slope failures, stream impacts and other natural resource damages, and we may as a result also be subject to increased operating expenses or environmental penalties and fines.

Terrorist attacks or cyber-attacks could have a material adverse effect on our business, financial condition or results of operations.

Terrorist attacks or cyber-attacks may significantly affect the energy industry, including our operations and those of Oasis and our other potential customers, as well as general economic conditions, consumer confidence and spending and market liquidity. Strategic targets, such as energy-related assets, may be at greater risk of future attacks than other targets in the United States. Our insurance may not protect us against such occurrences. Consequently, it is possible that any of these occurrences, or a combination of them, could have a material adverse effect on our business, financial condition and results of operations.

A cyber incident could result in information theft, data corruption, operational disruption and/or financial loss.

The oil and gas industry has become increasingly dependent on digital technologies to conduct day-to-day operations, including certain midstream activities. For example, software programs are used to manage gathering

 

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and transportation systems and for compliance reporting. The use of mobile communication devices has increased rapidly. Industrial control systems such as SCADA (supervisory control and data acquisition) now control large scale processes that can include multiple sites and long distances, such as oil and gas pipelines. We depend on digital technology, including information systems and related infrastructure as well as cloud applications and services, to process and record financial and operating data and to communicate with our employees and business partners. Our business partners, including vendors, service providers and financial institutions, are also dependent on digital technology. The technologies needed to conduct midstream activities make certain information the target of theft or misappropriation.

As dependence on digital technologies has increased, cyber incidents, including deliberate attacks or unintentional events, also has increased. A cyber attack could include gaining unauthorized access to digital systems for purposes of misappropriating assets or sensitive information, corrupting data or causing operational disruption. SCADA-based systems are potentially vulnerable to targeted cyber attacks due to their critical role in operations.

Our technologies, systems and networks, and those of our business partners, may become the target of cyber attacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information or other disruption of our business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period.

A cyber incident involving our information systems and related infrastructure, or that of our business partners, could disrupt our business plans and negatively impact our operations in the following ways, among others:

 

    a cyber attack on a vendor or service provider could result in supply chain disruptions, which could delay or halt development of additional infrastructure, effectively delaying the start of cash flows from the project;

 

    a cyber attack on downstream pipelines could prevent us from delivering product at the tailgate of our facilities, resulting in a loss of revenues;

 

    a cyber attack on a communications network or power grid could cause operational disruption resulting in loss of revenues;

 

    a deliberate corruption of our financial or operational data could result in events of non-compliance that could lead to regulatory fines or penalties; and

 

    business interruptions could result in expensive remediation efforts, distraction of management, damage to our reputation or a negative impact on the price of our units.

Our implementation of various controls and processes, including globally incorporating a risk-based cyber security framework, to monitor and mitigate security threats and to increase security for our information, facilities and infrastructure is costly and labor intensive. Moreover, there can be no assurance that such measures will be sufficient to prevent security breaches from occurring. As cyber threats continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any information security vulnerabilities.

Risks Inherent in an Investment in Us

Our general partner and its affiliates, including Oasis, which will own our general partner, may have conflicts of interest with us and limited duties to us and our unitholders, and they may favor their own interests to the detriment of us and our other common unitholders.

Following this offering, Oasis will own and control our general partner and will appoint all of the officers and directors of our general partner. All of our initial officers and a majority of our initial directors will also be

 

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officers and/or directors of Oasis. Although our general partner has a duty to manage us in a manner that it believes is not adverse to our interest, the directors and officers of our general partner have a fiduciary duty to manage our general partner in a manner that is beneficial to Oasis. Further, our directors and officers who are also directors and officers of Oasis have a fiduciary duty to manage Oasis in the best interests of the stockholders of Oasis. Conflicts of interest will arise between Oasis and any of its affiliates, including our general partner, on the one hand, and us and our common unitholders, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of Oasis over our interests and the interests of our unitholders. These conflicts include the following situations, among others:

 

    neither our partnership agreement nor any other agreement requires Oasis to pursue a business strategy that favors us;

 

    Oasis, as our anchor customer, has an economic incentive to cause us not to seek higher fees, even if such higher fees would reflect fees that could be obtained in arm’s-length, third-party transactions;

 

    Oasis may choose to shift the focus of its investment and operations to areas not served by our assets;

 

    actions taken by our general partner may affect the amount of cash available to pay distributions to unitholders or accelerate the right to convert subordinated units;

 

    the directors and officers of Oasis have a fiduciary duty to make decisions in the best interests of the stockholders of Oasis, which may be contrary to our interests;

 

    our general partner is allowed to take into account the interests of parties other than us, such as Oasis, in exercising certain rights under our partnership agreement, including with respect to conflicts of interest;

 

    except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval;

 

    our general partner may cause us to borrow funds in order to permit the payment of cash distributions;

 

    disputes may arise under our agreements with Oasis and its affiliates;

 

    our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates, including our contractual commercial agreements with Oasis;

 

    our general partner determines the amount and timing of asset purchases and sales, borrowings, issuances of additional partnership securities and the level of reserves, each of which can affect the amount of cash that is distributed to our unitholders;

 

    our general partner determines the amount and timing of any cash expenditure and whether a cash expenditure is classified as a maintenance capital expenditure, which reduces operating surplus. Please read “How We Make Distributions to Our Partners—Characterization of Cash Distributions—Cash Expenditures.” This determination can affect the amount of cash from operating surplus that is distributed to our unitholders which, in turn, may affect the ability of the subordinated units to convert. Please read “How We Make Distributions to Our Partners—Subordination Period”;

 

    our partnership agreement limits the liability of, and replaces the duties owed by, our general partner and also restricts the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty;

 

    common unitholders have no right to enforce obligations of our general partner and its affiliates under agreements with us;

 

    contracts between us, on the one hand, and our general partner and its affiliates, on the other, are not and will not be the result of arm’s-length negotiations;

 

    our partnership agreement permits us to distribute up to $         million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources that would otherwise constitute capital surplus, which may be used to fund distributions on our subordinated units or the incentive distribution rights;

 

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    our general partner determines which costs incurred by it and its affiliates are reimbursable by us;

 

    our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with its affiliates on our behalf;

 

    our general partner intends to limit its liability regarding our contractual and other obligations;

 

    our general partner may exercise its right to call and purchase common units if it and its affiliates own more than 80% of the common units;

 

    we may not choose to retain separate counsel for ourselves or for the holders of common units;

 

    our general partner’s affiliates may compete with us, and our general partner and its affiliates have limited obligations to present business opportunities to us; and

 

    the holder or holders of our incentive distribution rights may elect to cause us to issue common units to it in connection with a resetting of incentive distribution levels without the approval of our unitholders, which may result in lower distributions to our common unitholders in certain situations.

Please read “Conflicts of Interest and Fiduciary Duties.”

Ongoing cost reimbursements due to our general partner and its affiliates for services provided, which will be determined by our general partner, may be substantial and will reduce our distributable cash.

Prior to making distributions on our common units, we will reimburse our general partner and its affiliates for all expenses they incur on our behalf. These expenses will include all costs incurred by our general partner and its affiliates in managing and operating us, including costs for rendering administrative staff and support services to us and reimbursements paid by our general partner to Oasis for customary management and general administrative services. There is no limit on the amount of expenses for which our general partner and its affiliates may be reimbursed. Our partnership agreement provides that our general partner will determine the expenses that are allocable to us. In addition, under Delaware partnership law, our general partner has unlimited liability for our obligations, such as our debts and environmental liabilities, except for our contractual obligations that are expressly made without recourse to our general partner. To the extent our general partner incurs obligations on our behalf, we are obligated to reimburse or indemnify it. If we are unable or unwilling to reimburse or indemnify our general partner, our general partner may take actions to cause us to make payments of these obligations and liabilities. Any such payments could reduce the amount of our distributable cash.

We expect to distribute a significant portion of our distributable cash to our partners, which could limit our ability to grow and make acquisitions.

We plan to distribute most of our distributable cash and will rely primarily upon extended financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. As a result, to the extent we are unable to finance growth externally, our cash distribution policy may cause our growth to proceed at a slower pace than that of businesses that reinvest their cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no limitations in our partnership agreement on our ability to issue additional units, including units ranking senior to the common units. In addition, the incurrence of commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn, may reduce the cash that we have available to distribute to our unitholders.

 

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Our partnership agreement replaces our general partner’s fiduciary duties to holders of our common units with contractual standards governing its duties.

Our partnership agreement contains provisions that eliminate and replace the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner, or otherwise, free of fiduciary duties to us and our unitholders. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our limited partners. Examples of decisions that our general partner may make in its individual capacity include:

 

    how to allocate business opportunities among us and its other affiliates;

 

    whether to exercise its call right;

 

    whether to seek approval of the resolution of a conflict of interest by the conflicts committee of the board of directors of the general partner;

 

    how to exercise its voting rights with respect to any units it owns;

 

    whether to exercise its registration rights; and

 

    whether or not to consent to any merger or consolidation of the partnership or amendment to the partnership agreement.

By purchasing a common unit, a unitholder agrees to be bound by our partnership agreement and approves of the elimination and replacement of fiduciary duties discussed above. Please read “Conflicts of Interest and Fiduciary Duties—Fiduciary Duties of Our General Partner.”

Our general partner may elect to convert the Partnership to a corporation for U.S. federal income tax purposes without unitholder consent.

Under our partnership agreement, if, in connection with the enactment of U.S. federal income tax legislation or a change in the official interpretation of existing U.S. federal income tax legislation by a governmental authority, our general partner determines that (i) the Partnership should no longer be characterized as a partnership for U.S. federal or applicable state and local income tax purposes or (ii) common units held by unitholders other than the general partner and its affiliates should be converted into or exchanged for interests in a newly formed entity taxed as a corporation or an entity taxable at the entity level for U.S. federal or applicable state and local income tax purposes whose sole asset is interests in the Partnership (“parent corporation”), then our general partner may, without unitholder approval, cause the Partnership to be treated as an entity taxable as a corporation or subject to entity-level taxation for U.S. federal or applicable state and local income tax purposes, whether by election of the Partnership or conversion of the Partnership or by any other means or methods, or cause the common units held by unitholders other than the general partner and its affiliates to be converted into or exchanged for interests in the parent corporation. Any such event may be taxable or nontaxable to our unitholders, depending on the form of the transaction. The tax liability, if any, of a unitholder as a result of such an event may vary depending on the unitholder’s particular situation and may vary from the tax liability of our general partner and Oasis. In addition, if our general partner causes an interest in the Partnership to be held by a parent corporation, Oasis may choose to retain their partnership interests in us rather than convert their partnership interests into parent corporation shares. Please read “Our Partnership Agreement—Election to be Treated as a Corporation.”

 

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Our partnership agreement restricts the remedies available to holders of our common units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

Our partnership agreement contains provisions that restrict the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our partnership agreement:

 

    provides that whenever our general partner, the board of directors of our general partner or any committee thereof (including the conflicts committee) makes a determination or takes, or declines to take, any other action in their respective capacities, our general partner, the board of directors of our general partner and any committee thereof (including the conflicts committee) is required to make such determination, or take or decline to take such other action, in the absence of bad faith, and will not be subject to any other or different standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity;

 

    provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as it acted in good faith, meaning that it believed that the decision was not adverse to the interest of our partnership;

 

    provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or their assignees resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its officers and directors, as the case may be, acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and

 

    provides that our general partner will not be in breach of its obligations under the partnership agreement to us or our unitholders if a transaction with an affiliate or the resolution of a conflict of interest is:

 

    approved by the conflicts committee of the board of directors of our general partner, although our general partner is not obligated to seek such approval; or

 

    approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner and its affiliates.

In connection with a situation involving a transaction with an affiliate or a conflict of interest, any determination by our general partner must be made in good faith. If an affiliate transaction or the resolution of a conflict of interest is not approved by our common unitholders or the conflicts committee and the board of directors of our general partner approves the affiliate transaction or resolution or course of action taken with respect to the conflict of interest, then it will be presumed that, in making its decision, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption and proving that such decision was not in good faith.

Our partnership agreement includes exclusive forum, venue and jurisdiction provisions. By purchasing a common unit, a limited partner is irrevocably consenting to these provisions regarding claims, suits, actions or proceedings and submitting to the exclusive jurisdiction of Delaware courts. Our partnership agreement also provides that any unitholder bringing an unsuccessful action will be obligated to reimburse us for any costs we have incurred in connection with such unsuccessful claim.

Our partnership agreement is governed by Delaware law. Our partnership agreement includes exclusive forum, venue and jurisdiction provisions designating Delaware courts as the exclusive venue for most claims, suits, actions and proceedings involving us or our officers, directors and employees. Please read “The Partnership Agreement—Applicable Law; Forum, Venue and Jurisdiction.” If a dispute were to arise between a limited partner and us or our officers, directors or employees, the limited partner may be required to pursue its legal remedies in Delaware which may be an inconvenient or distant location and which is considered to be a more

 

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corporate-friendly environment. In addition, if any unitholder brings any of the aforementioned claims, suits, actions or proceedings and such person does not obtain a judgment on the merits that substantially achieves, in substance and amount, the full remedy sought, then such person shall be obligated to reimburse us and our affiliates for all fees, costs and expenses of every kind and description, including but not limited to all reasonable attorneys’ fees and other litigation expenses, that the parties may incur in connection with such claim, suit, action or proceeding. These provisions may increase the costs of bringing lawsuits and have the effect of discouraging lawsuits against us and our general partner’s directors and officers. The enforceability of these provisions in other companies’ certificates of incorporation or similar governing documents has been challenged in legal proceedings, and it is possible that in connection with any action a court could find these provisions contained in our partnership agreement to be inapplicable or unenforceable in such action. If a court were to find these provisions inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our business, financial condition and results of operations and our ability to make cash distributions to our unitholders. By purchasing a common unit, a limited partner is irrevocably consenting to these provisions and potential reimbursement obligations regarding claims, suits, actions or proceedings and submitting to the exclusive jurisdiction of Delaware courts. The potential reimbursement obligation provision may be applied to claims alleged to arise under federal securities laws, including claims related to this offering. To the extent that the potential reimbursement obligation provision is purported to apply to a claim arising under federal securities laws, it has not been judicially determined whether such a provision contradicts public policy expressed in the Securities Act, and thus a court may conclude that the potential reimbursement obligation provision is unenforceable. For additional information about the potential obligation to reimburse us for all fees, costs and expenses incurred in connection with claims, suits, actions or proceedings initiated by a unitholder that are not successful, please read “The Partnership Agreement—Reimbursement of Partnership Litigation Costs.”

Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors, which could reduce the price at which our common units will trade.

Compared to the holders of common stock in a corporation, unitholders have limited voting rights and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders will have no right on an annual or ongoing basis to elect our general partner or its board of directors. The board of directors of our general partner, including the independent directors, is chosen entirely by Oasis, as a result of it owning our general partner, and not by our unitholders. Furthermore, if our unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. Please read “Management—Management of Oasis Midstream Partners LP” and “Certain Relationships and Related Party Transactions.” Unlike publicly traded corporations, we will not conduct annual meetings of our unitholders to elect directors or conduct other matters routinely conducted at annual meetings of stockholders of corporations. As a result of these limitations, the price at which our common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.

Even if holders of our common units are dissatisfied, they cannot initially remove our general partner without its consent.

Unitholders initially will be unable to remove our general partner without its consent because our general partner and its affiliates, including Oasis, will own sufficient units upon the closing of this offering to be able to prevent its removal. Our general partner may not be removed except for cause by vote of the holders of at least 662/3% of all outstanding common and subordinated units, including any units owned by our general partner and its affiliates, voting together as a single class. Following the closing of this offering, Oasis will own    % of our outstanding common and subordinated units (excluding common units purchased by certain of our officers, directors, employees and certain other persons affiliated with us under our directed unit program). Cause is narrowly defined to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding our general partner liable for actual fraud or willful misconduct in its capacity as our general partner.

 

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Our general partner intends to limit its liability regarding our obligations.

Our general partner intends to limit its liability under contractual arrangements between us and third parties so that the counterparties to such arrangements have recourse only against our assets, and not against our general partner or its assets. Our general partner may therefore cause us to incur indebtedness or other obligations that are nonrecourse to our general partner. Our partnership agreement provides that any action taken by our general partner to limit its liability is not a breach of our general partner’s duties, even if we could have obtained more favorable terms without the limitation on liability. In addition, we are obligated to reimburse or indemnify our general partner to the extent that it incurs obligations on our behalf. Any such reimbursement or indemnification payments would reduce the amount of our distributable cash.

Our general partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to our incentive distribution rights, without the approval of the conflicts committee of our general partner’s board of directors or the holders of our common units. This could result in lower distributions to holders of our common units.

Our general partner has the right, as the initial holder of our incentive distribution rights, at any time when there are no subordinated units outstanding and it has received incentive distributions at the highest level to which it is entitled (50%) for the prior four consecutive fiscal quarters, to reset the initial target distribution levels at higher levels based on our distributions at the time of the exercise of the reset election. Following a reset election, the minimum quarterly distribution will be adjusted to equal the reset minimum quarterly distribution, and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution.

If our general partner elects to reset the target distribution levels, it will be entitled to receive a number of common units. The number of common units to be issued to our general partner will equal the number of common units that would have entitled our general partner to an aggregate quarterly cash distribution in the quarter prior to the reset election equal to the distribution on the incentive distribution rights in the quarter prior to the reset election. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion. It is possible, however, that our general partner or a transferee could exercise this reset election at a time when it is experiencing, or expects to experience, declines in the cash distributions it receives related to its incentive distribution rights and may, therefore, desire to be issued common units rather than retain the right to receive incentive distributions based on the initial target distribution levels. This risk could be elevated if our incentive distribution rights have been transferred to a third party. As a result, a reset election may cause our common unitholders to experience a reduction in the amount of cash distributions that our common unitholders would have otherwise received had we not issued new common units to our general partner in connection with resetting the target distribution levels. Our general partner may transfer all or a portion of the incentive distribution rights in the future. After any such transfer, the holder or holders of a majority of our incentive distribution rights will be entitled to exercise the right to reset the target distribution levels. Please read “How We Make Distributions to Our Partners—Right to Reset Incentive Distribution Levels.”

The incentive distribution rights held by our general partner may be transferred to a third party without unitholder consent.

Our general partner may transfer our incentive distribution rights to a third party at any time without the consent of our unitholders. If our general partner transfers our incentive distribution rights to a third party but retains its ownership of our general partner interest, it may not have the same incentive to grow our partnership and increase quarterly distributions to unitholders over time as it would if it had retained ownership of our incentive distribution rights. For example, a transfer of incentive distribution rights by our general partner could reduce the likelihood of our general partner selling or contributing additional assets to us, as our general partner would have less of an economic incentive to grow our business, which in turn would impact our ability to grow our asset base.

 

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Units held by persons who our general partner determines are not “eligible holders” at the time of any requested certification in the future may be subject to redemption.

As a result of certain laws and regulations to which we are or may in the future become subject, we may require owners of our common units to certify that they are both U.S. citizens and subject to U.S. federal income taxation on our income. Units held by persons who our general partner determines are not “eligible holders” at the time of any requested certification in the future may be subject to redemption. “Eligible holders” are holders of our common units whose (or whose owners’) (i) U.S. federal income tax status or lack of proof of U.S. federal income tax status does not have and is not reasonably likely to have, as determined by our general partner, a material adverse effect on the rates that can be charged to customers by us or our subsidiaries with respect to assets that are subject to regulation by FERC or any similar regulatory body and (ii) nationality, citizenship or other related status does not create, as determined by our general partner, a substantial risk of cancellation or forfeiture of any property in which we have an interest. The aggregate redemption price for redeemable interests will be an amount equal to the current market price (the date of determination of which will be the date fixed for redemption) of our common units multiplied by the number of common units included among the redeemable interests. For these purposes, the “current market price” means, as of any date, the average of the daily closing prices of our common units for the 20 consecutive trading days immediately prior to such date. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner. The units held by any person the general partner determines is not an eligible holder will not be entitled to voting rights. Please read “The Partnership Agreement—Non-Taxpaying Holders; Redemption” and “The Partnership Agreement—Non-Citizen Assignees; Redemption.”

Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units.

Unitholders’ voting rights are further restricted by the partnership agreement provision providing that any units held by a person or group that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates (including Oasis), their transferees and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot vote on any matter.

Control of our general partner may be transferred to a third party without unitholder consent.

Our general partner may transfer its general partner interest to a third party without the consent of our unitholders. Furthermore, our partnership agreement does not restrict the ability of the owners of our general partner from transferring all or a portion of their respective ownership interest in our general partner to a third party. The new owners of our general partner would then be in a position to replace the board of directors and officers of our general partner with their own choices and thereby exert significant control over the decisions made by the board of directors and officers. This effectively permits a “change of control” without the vote or consent of the unitholders.

Unitholders will experience immediate dilution in tangible net book value of $         per common unit.

The assumed initial public offering price of $         per unit exceeds our pro forma net tangible book value of $         per unit. Based on the assumed initial public offering price of $         per unit, you will incur immediate and substantial dilution of $         per common unit after giving effect to the offering of common units and the application of the related net proceeds. Dilution results primarily because the assets being contributed by our general partner and its affiliates are recorded in accordance with GAAP at their historical cost and not their fair value. Please read “Dilution.”

 

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We may issue additional units, including units that are senior to the common units, without unitholder approval, which would dilute unitholders’ existing ownership interests.

Our partnership agreement does not limit the number of additional partner interests that we may issue at any time without the approval of our unitholders. The issuance by us of additional common units or other equity interests of equal or senior rank will have the following effects:

 

    each unitholder’s proportionate ownership interest in us will decrease;

 

    the amount of our distributable cash per unit may decrease;

 

    because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;

 

    the ratio of taxable income to distributions may increase;

 

    the relative voting strength of each previously outstanding unit may be diminished; and

 

    the market price of the common units may decline.

Oasis may sell common units in the public or private markets, which sales could have an adverse impact on the trading price of the common units.

After the sale of the common units offered hereby, Oasis will hold             common units and all subordinated units. All of the subordinated units will convert into common units at the end of the subordination period and some may convert earlier. Additionally, we have agreed to provide Oasis with certain registration rights, pursuant to which we may be required to register common and subordinated units it holds under the Securities Act and applicable state securities laws. Pursuant to the registration rights agreement and our partnership agreement, we may be required to undertake a future public or private offering of common and subordinated units. The sale of these units in public or private markets could have an adverse impact on the price of the common units or on any trading market that may develop. Please read “Units Eligible for Future Sale.”

Our general partner’s discretion in establishing cash reserves may reduce the amount of distributable cash we have to distribute to unitholders.

Our partnership agreement requires our general partner to deduct from operating surplus the cash reserves that it determines are necessary to fund our future operating expenditures. In addition, the partnership agreement permits the general partner to reduce distributable cash by establishing cash reserves for the proper conduct of our business, to comply with applicable law or agreements to which we are a party, or to provide funds for future distributions to partners. These cash reserves will affect the amount of distributable cash we have available to distribute to unitholders.

Affiliates of our general partner, including Oasis, may compete with us, and neither our general partner nor its affiliates have any obligation to present business opportunities to us except with respect to our ROFO Assets and dedications contained in our commercial agreements with Oasis.

None of our partnership agreement, our omnibus agreement, our commercial agreements with Oasis or any other agreement in effect as of the date of this offering will prohibit Oasis or any other affiliates of our general partner from owning assets or engaging in businesses that compete directly or indirectly with us. Under the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, will not apply to our general partner or any of its affiliates, including Oasis and executive officers and directors of our general partner. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will not have any duty to communicate or offer such opportunity to us except with respect to our ROFO Assets and dedications contained in our commercial agreements with Oasis. Any such person or entity will not be liable to us or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself,

 

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directs such opportunity to another person or entity or does not communicate such opportunity or information to us. Consequently, Oasis and other affiliates of our general partner may acquire, construct or dispose of additional midstream assets in the future without any obligation to offer us the opportunity to purchase any of those assets. As a result, competition from Oasis and other affiliates of our general partner could materially and adversely impact our results of operations and distributable cash.

Our general partner has a call right that may require unitholders to sell their common units at an undesirable time or price.

If at any time our general partner and its affiliates (including Oasis) own more than 80% of the common units, our general partner will have the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price equal to the greater of (i) the average of the daily closing price of the common units over the 20 trading days preceding the date three days before notice of exercise of the call right is first mailed and (ii) the highest per-unit price paid by our general partner or any of its affiliates for common units during the 90-day period preceding the date such notice is first mailed. As a result, unitholders may be required to sell their common units at an undesirable time or price and may not receive any return or a negative return on their investment. Unitholders may also incur a tax liability upon a sale of their units. Our general partner is not obligated to obtain a fairness opinion regarding the value of the common units to be repurchased by it upon exercise of the limited call right. There is no restriction in our partnership agreement that prevents our general partner from causing us to issue additional common units and then exercising its call right. If our general partner exercised its limited call right, the effect would be to take us private and, if the units were subsequently deregistered, we would no longer be subject to the reporting requirements of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Upon consummation of this offering, and assuming the underwriters do not exercise their option to purchase additional common units, our general partner and its affiliates (including Oasis) will own an aggregate of             % of our common and all of our subordinated units (excluding common units purchased by certain of our officers, directors, employees and certain other persons affiliated with us under our directed unit program). At the end of the subordination period, assuming no additional issuances of units (other than upon the conversion of the subordinated units), our general partner and its affiliates will own             % of our common units (excluding common units purchased by certain of our officers, directors, employees and certain other persons affiliated with us under our directed unit program). For additional information about the limited call right, please read “The Partnership Agreement—Limited Call Right.”

Unitholder liability may not be limited if a court finds that unitholder action constitutes control of our business.

A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law, and we will initially own assets and conduct business in North Dakota and Montana. A unitholder could be liable for any and all of our obligations as if such unitholder were a general partner if:

 

    a court or government agency determined that we were conducting business in a state but had not complied with that particular state’s partnership statute; or

 

    such unitholder’s right to act with other unitholders to remove or replace the general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute “control” of our business.

For a discussion of the implications of the limitations of liability on a unitholder, please read “The Partnership Agreement—Limited Liability.”

 

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Unitholders may have liability to repay distributions that were wrongfully distributed to them.

Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Act, we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Liabilities to partners on account of their partnership interest and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.

There is no existing market for our common units, and a trading market that will provide unitholders with adequate liquidity may not develop. The price of our common units may fluctuate significantly, which could cause unitholders to lose all or part of their investment.

Prior to this offering, there has been no public market for the common units. After this offering, there will be only             publicly traded common units (assuming no exercise of the underwriters’ option to purchase additional common units). In addition, Oasis will own             common units and             subordinated units, representing an aggregate approximately     % limited partner interest in us. We do not know the extent to which investor interest will lead to the development of a trading market or how liquid that market might be. Unitholders may not be able to resell their common units at or above the initial public offering price. Additionally, a lack of liquidity may result in wide bid-ask spreads, contribute to significant fluctuations in the market price of the common units and limit the number of investors who are able to buy the common units.

The initial public offering price for the common units will be determined by negotiations between us and the representatives of the underwriters and may not be indicative of the market price of the common units that will prevail in the trading market. The market price of our common units may decline below the initial public offering price. The market price of our common units may also be influenced by many factors, some of which are beyond our control, including:

 

    our quarterly distributions;

 

    our quarterly or annual earnings or those of other companies in our industry;

 

    events affecting Oasis;

 

    announcements by us or our competitors of significant contracts or acquisitions;

 

    changes in accounting standards, policies, guidance, interpretations or principles;

 

    general economic conditions;

 

    the failure of securities analysts to cover our common units after the consummation of this offering or changes in financial estimates by analysts;

 

    future sales of our common units; and

 

    other factors described in these “Risk Factors.”

If we fail to develop or maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential unitholders could lose confidence in our financial reporting, which would harm our business and the trading price of our units.

Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public company. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed. We cannot be certain that our efforts to develop and maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to comply with our obligations under Section 404 of

 

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the Sarbanes Oxley Act of 2002. Any failure to develop or maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our units.

For as long as we are an “emerging growth company,” we will not be required to comply with certain disclosure requirements that apply to other public companies.

We are classified as an “emerging growth company” under the JOBS Act. For as long as we are an “emerging growth company,” which may be up to five full fiscal years, unlike other public companies, we will not be required to, among other things, (1) provide an auditor’s attestation report on the effectiveness of our system of internal control over financial reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act, (2) comply with any new requirements adopted by the Public Company Accounting Oversight Board requiring mandatory audit firm rotation or a supplement to the auditor’s report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer, (3) provide certain disclosure regarding executive compensation required of larger public companies or (4) hold nonbinding advisory votes on executive compensation. We will remain an “emerging growth company” for up to five years, although we will lose that status sooner if we have more than $1.07 billion of revenues in a fiscal year, become a large accelerated filer, or issue more than $1.07 billion of non-convertible debt cumulatively over a three-year period.

To the extent that we rely on any of the exemptions available to “emerging growth companies,” you will receive less information about our executive compensation and internal control over financial reporting than issuers that are not “emerging growth companies.” If some investors find our common units to be less attractive as a result, there may be a less active trading market for our common units and our trading price may be more volatile.

The New York Stock Exchange does not require a publicly traded partnership like us to comply with certain of its corporate governance requirements.

We intend to apply to list our common units on the NYSE. Because we will be a publicly traded partnership, the NYSE does not require us to have a majority of independent directors on our general partner’s board of directors or to establish a compensation committee or a nominating and corporate governance committee. Accordingly, unitholders will not have the same protections afforded to stockholders of certain corporations that are subject to all of the NYSE corporate governance requirements. Please read “Management—Management of Oasis Midstream Partners LP.”

We will incur increased costs as a result of being a publicly traded partnership.

We have no history operating as a publicly traded partnership. As a publicly traded partnership, we will incur significant legal, accounting and other expenses that we did not incur prior to this offering. In addition, the Sarbanes-Oxley Act of 2002, as well as rules implemented by the SEC and the NYSE, require publicly traded entities to adopt various corporate governance practices that will further increase our costs. Before we are able to make distributions to our unitholders, we must first pay or reserve cash for our expenses, including the costs of being a publicly traded partnership. As a result, the amount of our distributable cash will be affected by the costs associated with being a publicly traded partnership.

Prior to this offering, we have not filed reports with the SEC. Following this offering, we will become subject to the public reporting requirements of the Exchange Act. We expect these rules and regulations to increase certain of our legal and financial compliance costs and to make activities more time-consuming and costly. For example, as a result of becoming a publicly traded partnership, we are required to have at least three independent directors, create an audit committee and adopt policies regarding internal controls and disclosure controls and procedures, including the preparation of reports on internal controls over financial reporting. In addition, we will incur additional costs associated with our SEC reporting requirements.

 

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We also expect to incur significant expense in order to obtain director and officer liability insurance. Because of the limitations in coverage for directors, it may be more difficult for us to attract and retain qualified persons to serve on our board or as executive officers.

We estimate that we will incur approximately $2.5 million of incremental costs per year associated with being a publicly traded partnership; however, it is possible that our actual incremental costs of being a publicly traded partnership will be higher than we currently estimate.

If we are an “investment company” under the Investment Company Act of 1940, it would adversely affect the price of our common units and could have a material adverse effect on our business.

Our initial assets will consist of direct and indirect ownership interests in our DevCos. If a sufficient amount of our assets now owned or in the future acquired are deemed to be “investment securities” within the meaning of the Investment Company Act of 1940, or the Investment Company Act, we would either have to register as an investment company under the Investment Company Act, obtain exemptive relief from the SEC or modify our organizational structure or our contract rights to fall outside the definition of an investment company. Treatment of us as an investment company would prevent our qualification as a partnership for federal income tax purposes, in which case we would be treated as a corporation for federal income tax purposes. As a result, we would pay federal income tax on our taxable income at the corporate tax rate, distributions to you would generally be taxed again as corporate dividends and none of our income, gains, losses or deductions would flow through to you. Because a tax would be imposed upon us as a corporation, our distributable cash would be substantially reduced. Therefore, treatment of us as an investment company would result in a material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our common units. Please read “Material U.S. Federal Income Tax Consequences—Taxation of the Partnership.”

Moreover, registering as an investment company could, among other things, materially limit our ability to engage in transactions with affiliates, including the purchase of additional interests in our DevCos from Oasis, restrict our ability to borrow funds or engage in other transactions involving leverage and require Oasis us to add directors who are independent of us or our affiliates to our board. The occurrence of some or all of these events would adversely affect the price of our common units and could have a material adverse effect on our business.

Tax Risks to Common Unitholders

In addition to reading the following risk factors, unitholders should read “Material U.S. Federal Income Tax Consequences” for a more complete discussion of the expected material federal income tax consequences of owning and disposing of common units.

Our tax treatment depends on our status as a partnership for federal income tax purposes and not being subject to a material amount of entity-level taxation. If the IRS were to treat us as a corporation for federal income tax purposes, or if we become subject to entity-level taxation for state tax purposes, our distributable cash would be substantially reduced.

The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes.

Despite the fact that we are organized as a limited partnership under Delaware law, we would be treated as a corporation for U.S. federal income tax purposes unless we satisfy a “qualifying income” requirement. Based upon our current operations, we believe we satisfy the qualifying income requirement. We have requested and received a private letter ruling from the IRS to the effect that certain of our income constitutes qualifying income. However, no ruling has been or will be requested regarding our treatment as a partnership for U.S. federal income tax purposes. Failing to meet the qualifying income requirement or a change in current law could cause us to be treated as a corporation for U.S. federal income tax purposes or otherwise subject us to taxation as an entity.

 

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If we were treated as a corporation for federal income tax purposes, we would pay U.S. federal income tax on our taxable income at the corporate tax rate. Distributions to you would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to you. Because a tax would be imposed upon us as a corporation, our distributable cash would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our common units.

At the state level, several states have been evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise or other forms of taxation. We currently own assets and conduct business in several states that impose a margin or franchise tax. In the future, we may expand our operations. Imposition of a similar tax on us in other jurisdictions that we may expand to could substantially reduce our distributable cash. Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for U.S. federal, state, local or foreign income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law or interpretation on us.

The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes or differing interpretations, possibly applied on a retroactive basis.

The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial changes or differing interpretations at any time.

From time to time, members of Congress have proposed and considered substantive changes to the existing U.S. federal income tax laws that would affect publicly traded partnerships. Although there is no current legislative proposal, a prior legislative proposal would have eliminated the qualifying income exception to the treatment of all publicly traded partnerships as corporations upon which we rely for our treatment as a partnership for U.S. federal income tax purposes.

In addition, on January 24, 2017, final regulations regarding which activities give rise to qualifying income within the meaning of Section 7704 of the Code (the “Final Regulations”) were published in the Federal Register. The Final Regulations are effective as of January 19, 2017, and apply to taxable years beginning on or after January 19, 2017. We do not believe the Final Regulations affect our ability to be treated as a partnership for U.S. federal income tax purposes.

However, any modification to the U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible for us to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes. We are unable to predict whether any of these changes or other proposals will ultimately be enacted. Any similar or future legislative changes could negatively impact the value of an investment in our common units.

For a discussion of the importance of our treatment as a partnership for federal income purposes, please read “Material U.S. Federal Income Tax Consequences—Taxation of the Partnership—Partnership Status.”

If the IRS were to contest the federal income tax positions we take, it may adversely impact the market for our common units, and the costs of any such contest would reduce our distributable cash.

We have not requested a ruling from the IRS with respect to our treatment as a partnership for U.S. federal income tax purposes. The IRS may adopt positions that differ from the conclusions of our counsel expressed in this prospectus or from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel’s conclusions or the positions we take. A court may not agree with some or

 

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all of our counsel’s conclusions or positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. Moreover, the costs of any contest between us and the IRS will result in a reduction in our distributable cash and thus will be borne indirectly by our unitholders.

If the IRS makes audit adjustments to our income tax returns for tax years beginning after December 31, 2017, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustments directly from us, in which case our distributable cash might be substantially reduced.

Pursuant to the Bipartisan Budget Act of 2015, for tax years beginning after December 31, 2017, if the IRS makes audit adjustments to our income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustments directly from us. To the extent possible under the new rules, our general partner may elect to either pay the taxes (including any applicable penalties and interest) directly to the IRS or, if we are eligible, issue a revised Schedule K-1 to each unitholder with respect to an audited and adjusted return. Although our general partner may elect to have our unitholders take such audit adjustment into account in accordance with their interests in us during the tax year under audit, there can be no assurance that such election will be practical, permissible or effective in all circumstances. As a result, our unitholders may bear some or all of the tax liability resulting from such audit adjustment, even if such unitholders did not own common units in us during the tax year under audit. If, as a result of any such audit adjustment, we are required to make payments of taxes, penalties and interest, our distributable cash might be substantially reduced. These rules are not applicable for tax years beginning on or prior to December 31, 2017.

For a discussion of the importance of our treatment as a partnership for federal income purposes, please read “Material U.S. Federal Income Tax Consequences—Administrative Matters—Information Returns and Audit Procedures.”

Even if unitholders do not receive any cash distributions from us, they will be required to pay taxes on their share of our taxable income.

Unitholders will be required to pay U.S. federal income taxes and, in some cases, state and local income taxes on their share of our taxable income whether or not they receive cash distributions from us. Unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax due from them with respect to that income.

Tax gain or loss on disposition of our common units could be more or less than expected.

If a unitholder sells common units, the unitholder will recognize a gain or loss equal to the difference between the amount realized and that unitholder’s tax basis in those common units. Because distributions in excess of a unitholder’s allocable share of our net taxable income decrease such unitholder’s tax basis in its common units, the amount, if any, of such prior excess distributions with respect to the common units a unitholder sells will, in effect, become taxable income to a unitholder if it sells such common units at a price greater than its tax basis in those units, even if the price such unitholder receives is less than its original cost. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if a unitholder sells its common units it may incur a tax liability in excess of the amount of cash received from the sale.

A substantial portion of the amount realized from a unitholder’s sale of our units, whether or not representing gain, may be taxed as ordinary income to such unitholder due to potential recapture items, including depreciation recapture. Thus, a unitholder may recognize both ordinary income and capital loss from the sale of units if the amount realized on a sale of such units is less than such unitholder’s adjusted basis in the units. Net capital loss may only offset capital gains and, in the case of individuals, up to $3,000 of ordinary income per

 

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year. In the taxable period in which a unitholder sells its units, such unitholder may recognize ordinary income from our allocations of income and gain to such unitholder prior to the sale and from recapture items that generally cannot be offset by any capital loss recognized upon the sale of units.

Please read “Material U.S. Federal Income Tax Consequences—Disposition of Common Units—Recognition of Gain or Loss” for a further discussion.

Tax-exempt entities and non-U.S. persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.

Investment in our common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from U.S. federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be subject to withholding taxes imposed at the highest effective tax rate applicable to such non-U.S. persons, and each non-U.S. person will be required to file U.S. federal tax returns and pay tax on their share of our taxable income. Tax-exempt entities and non-U.S. persons should consult a tax advisor before investing in our common units. Please read “Material U.S. Federal Income Tax Consequences—Tax-Exempt Organizations and Other Investors.”

We will treat each purchaser of common units as having the same tax benefits without regard to the common units actually purchased. The IRS may challenge this treatment, which could adversely affect the value of our common units.

Because we cannot match transferors and transferees of common units, we have adopted certain methods for allocating depreciation and amortization deductions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to the use of these methods could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain from any sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to a unitholder’s tax returns. Vinson & Elkins L.L.P. is unable to opine as to the validity of such filing positions. Please read “Material U.S. Federal Income Tax Consequences—Tax Consequences of Common Unit Ownership—Section 754 Election” and “Material U.S. Federal Income Tax Consequences—Uniformity of Common Units” for a further discussion on the use of these depreciation and amortization methodologies.

We will generally prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular common unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

We will generally prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month (the “Allocation Date”), instead of on the basis of the date a particular common unit is transferred. Similarly, we generally allocate certain deductions for depreciation of capital additions, gain or loss realized on a sale or other disposition of our assets and, in the discretion of the general partner, any other extraordinary item of income, gain, loss or deduction based upon ownership on the Allocation Date. Treasury Regulations allow a similar monthly simplifying convention, but such regulations do not specifically authorize all aspects of our proration method. Accordingly, Vinson & Elkins L.L.P. is unable to opine on the validity of our method of allocating income, gain, loss and deduction among transferor and transferee unitholders. If the IRS were to challenge our proration method, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders. Please read “Material U.S. Federal Income Tax Consequences—Disposition of Common Units—Allocations between Transferors and Transferees.”

 

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A unitholder whose common units are the subject of a securities loan (e.g., a loan to a “short seller” to cover a short sale of common units) may be considered to have disposed of those common units. If so, he would no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition.

Because there are no specific rules governing the U.S. federal income tax consequence of loaning a partnership interest, a unitholder whose common units are the subject of a securities loan may be considered to have disposed of the loaned common units. In that case, the unitholder may no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan, any of our income, gain, loss or deduction with respect to those common units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those common units could be fully taxable as ordinary income. Vinson & Elkins L.L.P. has not rendered an opinion regarding the treatment of a unitholder whose common units are the subject of a securities loan; therefore, unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a securities loan are urged to consult a tax advisor to determine whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their common units.

We will adopt certain valuation methodologies in determining a unitholder’s allocations of income, gain, loss and deduction. The IRS may challenge these methodologies or the resulting allocations, which could adversely affect the value of our common units.

In determining the items of income, gain, loss and deduction allocable to our unitholders, we must routinely determine the fair market value of our assets. Although we may, from time to time, consult with professional appraisers regarding valuation matters, we will make many fair market value estimates using a methodology based on the market value of our common units as a means to measure the fair market value of our assets. The IRS may challenge these valuation methods and the resulting allocations of income, gain, loss and deduction.

A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain recognized from the sale of our common units, have a negative impact on the value of our common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.

The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for U.S. federal income tax purposes.

We will be considered to have terminated our partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. Immediately after this offering, our sponsor will own more than 50% of the total interests in our capital and profits. Therefore, a transfer by our sponsor of all or a portion of its interests in us could, in conjunction with the trading of our common units held by the public, result in a termination of our partnership for federal income tax purposes. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest will be counted only once.

Our termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns for one calendar year and could result in a significant deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a calendar year, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in taxable income for the unitholder’s taxable year that includes our termination. Our termination would not affect our classification as a partnership for U.S. federal income tax purposes, but it would result in our being treated as a new partnership for U.S. federal income tax purposes following the termination. If we were treated as a new partnership, we would be required to make new

 

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tax elections and could be subject to penalties if we were unable to determine that a termination occurred. The IRS has announced a relief procedure whereby if a publicly traded partnership that has terminated requests and the IRS grants special relief, among other things, the partnership may be permitted to provide only a single Schedule K-1 to unitholders for the two short tax periods included in the year in which the termination occurs.

Please read “Material U.S. Federal Income Tax Consequences—Disposition of Common Units—Technical Termination” for a discussion of the consequences of our termination for U.S. federal income tax purposes.

Our unitholders will likely be subject to state and local taxes and income tax return filing requirements in jurisdictions where they do not live as a result of investing in our common units.

In addition to U.S. federal income taxes, our unitholders may be subject to other taxes, including foreign, state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if they do not live in any of those jurisdictions. Our unitholders will likely be required to file foreign, state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements.

We currently own assets and conduct business in multiple states that currently impose a personal income tax on individuals, corporations and other entities. As we make acquisitions or expand our business, we may own assets or conduct business in additional states that impose a personal income tax. It is our unitholders’ responsibility to file all U.S. federal, foreign, state and local tax returns. Vinson & Elkins L.L.P. has not rendered an opinion on the state, local or non-U.S. tax consequences of an investment in our common units. Prospective unitholders are urged to consult their tax advisor.

 

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

Some of the information in this prospectus may contain forward-looking statements. 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. All statements in this prospectus about distributable cash and our forecasted pro forma financial data constitute 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 in this prospectus. 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 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, including the ROFO Assets, on economically acceptable terms from Oasis;

 

    the lack of asset and geographic diversification;

 

    the suspension, reduction or termination of our commercial agreements with Oasis;

 

    labor relations and government regulations;

 

    competition and actions taken by third-party producers, operators, processors and transporters;

 

    pending legal or environmental matters;

 

    the demand for, and the costs of conducting, our midstream infrastructure services;

 

    general economic conditions;

 

    the price and availability of debt and equity financing;

 

    operating hazards, natural disasters, weather-related delays, casualty losses and other matters beyond our control;

 

    changes in our tax status;

 

    uncertainty regarding our future operating results; and

 

    certain other factors discussed elsewhere in this prospectus.

 

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We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to midstream businesses. These risks 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 “Risk Factors” in this prospectus.

Should one or more of the risks or uncertainties described in this prospectus occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.

All forward-looking statements, expressed or implied, included in this prospectus are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.

Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this prospectus.

 

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USE OF PROCEEDS

We intend to use the estimated net proceeds of approximately $         million from this offering (based on an assumed initial offering price of $         per common unit, the mid-point of the price range set forth on the cover page of this prospectus), after deducting the estimated underwriting discount and offering expenses (i) to make a distribution of approximately $         million to Oasis and (ii) to pay approximately $         million of origination fees and expenses related to our new revolving credit facility.

If and to the extent the underwriters exercise their option to purchase additional common units in full, we intend to use the additional net proceeds of approximately $         million upon such exercise to pay a distribution to Oasis. If the underwriters do not exercise their option to purchase additional common units, in whole or in part, any remaining common units not purchased by the underwriters pursuant to the option will be issued to Oasis at the expiration of the option period for no additional consideration. Accordingly, the exercise of the underwriters’ option will not affect the total number of common units outstanding or the amount of cash needed to pay the minimum quarterly distribution on all units. Please read “Underwriting.”

A $1.00 increase or decrease in the assumed initial public offering price of $         per common unit would cause the net proceeds from this offering, after deducting the estimated underwriting discount and offering expenses payable by us, to increase or decrease, respectively, by approximately $         million. In addition, we may also increase or decrease the number of common units we are offering. Each increase of 1.0 million common units offered by us, together with a $1.00 increase in the assumed public offering price to $         per common unit, would increase net proceeds to us from this offering by approximately $         million. Similarly, each decrease of 1.0 million common units offered by us, together with a $1.00 decrease in the assumed initial offering price to $         per common unit, would decrease the net proceeds to us from this offering by approximately $         million. Any increase or decrease in the net proceeds would change the amount of our distribution paid to Oasis.

 

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CAPITALIZATION

The following table shows our cash and cash equivalents and our capitalization as of March 31, 2017:

 

    on a historical basis for our Predecessor; and

 

    on a pro forma basis as of March 31, 2017, giving effect to the pro forma adjustments described in our unaudited pro forma condensed financial statements included elsewhere in this prospectus, including this offering and the application of the net proceeds of this offering in the manner described under “Use of Proceeds” and the other transactions described under “Summary—Formation Steps and Partnership Structure.”

This table is derived from, and should be read together with, the unaudited historical condensed financial statements of our Predecessor, the unaudited pro forma condensed financial statements and the accompanying notes included elsewhere in this prospectus. You should also read this table in conjunction with “Use of Proceeds” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

 

     As of March 31, 2017  
         Historical              Pro Forma      
     (in thousands)  

Cash and cash equivalents

   $      $  
  

 

 

    

 

 

 

Indebtedness:

     

New revolving credit facility(1)

   $      $  
  

 

 

    

 

 

 

Total long-term debt

         

Net parent investment/partners’ capital:

     

Total net parent investment

     347,707         

Common units—public

         

Common units—Oasis

         

Subordinated units—Oasis

         

General partner interest(2)

             
  

 

 

    

 

 

 

Total net parent investment/partners’ capital

     347,707     
  

 

 

    

 

 

 

Total capitalization

   $ 347,707      $  
  

 

 

    

 

 

 

 

(1) In connection with the completion of this offering, we expect to enter into a new revolving credit facility. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.”
(2) Our general partner owns a non-economic general partner interest in us.

 

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DILUTION

Dilution is the amount by which the offering price paid by the purchasers of common units sold in this offering will exceed the pro forma net tangible book value per common unit after the offering. Assuming an initial public offering price of $         per common unit (the mid-point of the price range set forth on the cover page of this prospectus), on a pro forma basis as of March 31, 2017, after giving effect to the offering of common units, the contribution of our initial interests in the DevCos and the related transactions, our net tangible book value would have been approximately $         million, or $         per common unit. Purchasers of our common units in this offering will experience substantial and immediate dilution in net tangible book value per common unit for financial accounting purposes, as illustrated in the following table:

 

Assumed initial public offering price per common unit

      $           

Pro forma net tangible book value per common unit before the offering(1)

   $              

Decrease in net tangible book value per common unit attributable to the interests in the DevCos retained by Oasis

     

Increase in net tangible book value per common unit attributable to purchasers in the offering

     

Decrease in net tangible book value per common unit attributable to the distribution to Oasis

     

Decrease in net tangible book value per common unit attributable to the reimbursement of Oasis for capital expenditures incurred prior to this offering

     

Less: Pro forma net tangible book value per common unit after the offering(2)

     
     

 

 

 

Immediate dilution in net tangible book value per common unit to purchasers in the offering(3)(4)

      $  
     

 

 

 

 

(1) Determined by dividing the pro forma net tangible book value by the number of units (         common units and         subordinated units) to be issued to Oasis for their contribution of assets and liabilities to us.
(2) Determined by dividing our pro forma net tangible book value, after giving effect to the use of the net proceeds of the offering, by the total number of units (         common units and             subordinated units) to be outstanding after the offering.
(3) A $1.00 increase or decrease in the assumed initial public offering price of $         per common unit would increase or decrease, respectively, our pro forma net tangible book value by approximately $         million, or approximately $         per common unit, and dilution per common unit to investors in this offering by approximately $         per common unit, after deducting the estimated underwriting discount and offering expenses payable by us. We may also increase or decrease the number of common units we are offering. Each increase of 1.0 million common units offered by us, together with a $1.00 increase in the assumed initial offering price to $         per common unit, would result in a pro forma net tangible book value of approximately $         million, or $         per common unit, and dilution per common unit to investors in this offering would be $         per common unit. Similarly, each decrease of 1.0 million common units offered by us, together with a $1.00 decrease in the assumed initial public offering price to $         per common unit, would result in an pro forma net tangible book value of approximately $         million, or $         per common unit, and dilution per common unit to investors in this offering would be $         per common unit. The information discussed above is illustrative only and will be adjusted based on the actual public offering price, the number of common units offered by us and other terms of this offering determined at pricing.
(4) Because the total number of units outstanding following this offering will not be impacted by any exercise of the underwriters’ option to purchase additional common units and any net proceeds from such exercise will not be retained by us, there will be no change to the dilution in net tangible book value per common unit to purchasers in the offering due to any such exercise of the option.

 

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The following table sets forth the number of units that we will issue and the total consideration contributed to us by Oasis and by the purchasers of our common units in this offering upon consummation of the transactions contemplated by this prospectus:

 

     Units     Total Consideration  
         Number              Percent             Number              Percent      

Oasis(1)(2)(3)

                                                

Purchasers in the offering(3)

                                
  

 

 

    

 

 

   

 

 

    

 

 

 

Total

        100        100
  

 

 

    

 

 

   

 

 

    

 

 

 

 

(1) Upon the consummation of the transactions contemplated by this prospectus, Oasis will own common units and subordinated units.
(2) The contribution of the assets of our Predecessor will be recorded at historical cost. The pro forma book value of the consideration provided by Oasis as of March 31, 2017, after giving effect to our reimbursement of Oasis for $         million of capital expenditures incurred on our behalf prior to the closing of this offering, the distribution to Oasis of $         million of excluded assets of our Predecessor that will not be contributed to us in connection with this offering and our distribution to Oasis of $         million concurrent with the closing of this offering, would have been approximately $         million.
(3) Assumes the underwriters’ option to purchase additional common units is not exercised.

 

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OUR CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

You should read the following discussion of our cash distribution policy in conjunction with the specific assumptions included in this section. In addition, you should read “Cautionary Statement Regarding Forward-Looking Statements” and “Risk Factors” for information regarding statements that do not relate strictly to historical or current facts and certain risks inherent in our business.

For additional information regarding our historical results of operations, you should refer to our Predecessor’s audited historical financial statements and the related notes to those statements as of and for the years ended December 31, 2016 and 2015 and the unaudited historical condensed financial statements and the related notes to those statements as of and for the three months ended March 31, 2017 and 2016 included elsewhere in this prospectus. For additional information regarding our unaudited pro forma condensed results of operations, you should refer to our unaudited pro forma condensed financial statements and the related notes to those statements as of March 31, 2017 and for the year ended December 31, 2016 and for the three months ended March 31, 2017 and 2016 included elsewhere in this prospectus.

General

Our Cash Distribution Policy

The board of directors of our general partner will adopt a cash distribution policy pursuant to which we intend to distribute at least the minimum quarterly distribution of $         per unit ($         per unit on an annualized basis) on all of our units to the extent we have sufficient cash after the establishment of cash reserves and the payment of our expenses, including payments to our general partner and its affiliates. Furthermore, we expect that if we are successful in executing our business strategy, we will grow our business in a steady and sustainable manner and distribute to our unitholders a portion of any increase in our distributable cash resulting from such growth.

Our cash distribution policy reflects a judgment that our unitholders will be better served by our distributing rather than retaining our distributable cash. Because we believe we will generally finance any expansion capital expenditures from external financing sources, including borrowings under our new revolving credit facility and the issuance of debt and equity securities, we believe that our investors are best served by distributing all of our distributable cash. Because we are not subject to an entity-level federal income tax, we expect to have more cash to distribute to you than would be the case if we were subject to tax.

The board of directors of our general partner may change our distribution policy at any time. Our partnership agreement does not require us to pay cash distributions quarterly or on any other basis.

Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy

There is no guarantee that we will make cash distributions to our unitholders. We do not have a legal or contractual obligation to pay cash distributions quarterly or on any other basis or at our minimum quarterly distribution rate or at any other rate. Our cash distribution policy is subject to certain restrictions and may be changed at any time.

The reasons for such uncertainties in our stated cash distribution policy include the following factors:

 

   

Our cash distribution policy will be subject to restrictions on cash distributions under our new revolving credit facility, which is expected to contain financial tests and covenants that we must satisfy. Our currently anticipated covenants would not have restricted our ability to make cash distributions during the pro forma periods for the year ended December 31, 2016 and the twelve months ended March 31, 2017 or the forecasted financial period for the twelve months ending June 30, 2018. However, should we be unable to satisfy these covenants or if we are otherwise in default under our new revolving credit facility, we will be prohibited from making cash distributions to you

 

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notwithstanding our stated cash distribution policy. Please read “Management’s Discussion and Analysis of Financial Condition” and “Results of Operations—Liquidity and Capital Resources—Oasis Midstream Partners LP Credit Agreement.”

 

    Our general partner will have the authority to establish cash reserves for the prudent conduct of our business, including for future cash distributions to our unitholders. The establishment of or increase in those reserves could result in a reduction in cash distributions from levels we currently anticipate pursuant to our stated cash distribution policy. Our partnership agreement does not set a limit on the amount of cash reserves established by our general partner.

 

    Prior to making any distribution on the common units, we will reimburse our general partner and its affiliates (including Oasis) for all direct and indirect general and administrative (“G&A”) expenses they incur on our behalf. Our partnership agreement does not set a limit on the amount of expenses for which our general partner and its affiliates may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. Please see the notes to the unaudited pro forma condensed financial statements included elsewhere in this prospectus for a description of the methodology behind how general and administrative expenses are allocated to us. Our obligations to reimburse our general partner and its affiliates are governed by our partnership agreement and the services and secondment agreement that we expect to enter into with our general partner and Oasis. The reimbursement of expenses and payment of fees, if any, to our general partner and its affiliates will reduce the amount of cash available to pay distributions to our unitholders.

 

    Even if our cash distribution policy is not modified or revoked, the amount of distributions we pay under our cash distribution policy and the decision to make any distribution is determined by our general partner.

 

    Under Section 17-607 of the Delaware Act, we may not make a distribution if the distribution would cause our liabilities to exceed the fair value of our assets.

 

    We may lack sufficient cash to pay distributions to our unitholders due to cash flow shortfalls attributable to a number of operational, commercial or other factors detailed in this prospectus as well as increases in our operating or general and administrative expenses, principal and interest payments on our debt, working capital requirements and anticipated cash needs. Our distributable cash is directly impacted by our cash expenses necessary to run our business and will be reduced dollar-for-dollar to the extent such uses of cash increase.

 

    If we make distributions out of capital surplus, as opposed to operating surplus, any such distributions would constitute a return of capital and would result in a reduction in the minimum quarterly distribution and the target distribution levels. Please read “How We Make Distributions to Our Partners—Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels.” We do not anticipate that we will make any distributions from capital surplus.

 

    If and to the extent our distributable cash materially declines, we may elect to reduce our quarterly cash distributions in order to service or repay our debt or fund expansion capital expenditures.

Our Ability to Grow may be Dependent on Our Ability to Access External Financing Sources

We expect to generally distribute a significant percentage of our cash from operations to our unitholders on a quarterly basis, after the establishment of cash reserves and payment of our expenses. Therefore, our growth may not be as fast as businesses that reinvest most or all of their cash to expand ongoing operations. Moreover, our future growth may be slower than our historical growth. We expect that we will rely primarily upon external financing sources, including borrowings under our new revolving credit facility and issuances of debt and equity securities, to fund our expansion capital expenditures. To the extent we are unable to finance growth externally, our cash distribution policy will significantly impair our ability to grow.

 

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Our Minimum Quarterly Distribution

Upon the consummation of this offering, our partnership agreement will provide for a minimum quarterly distribution of $         per unit for each whole quarter, or $         per unit on an annualized basis. The payment of the full minimum quarterly distribution on all of the common units and subordinated units to be outstanding after completion of this offering would require us to have distributable cash of approximately $         million per quarter, or $         million per year. Our ability to make cash distributions at the minimum quarterly distribution rate will be subject to the factors described above under “—General—Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy.”

The table below sets forth the amount of common units and subordinated units that will be outstanding immediately after this offering and the distributable cash needed to pay the aggregate minimum quarterly distribution on all of such units for a single fiscal quarter and a four-quarter period:

 

     Number of Units      Minimum Quarterly
Distributions
 
        One Quarter      Annualized  

Common units held by the public(1)(2)

      $                   $               

Common units held by Oasis(1)

        

Subordinated units held by Oasis

        
  

 

 

    

 

 

    

 

 

 

Total

      $      $  
  

 

 

    

 

 

    

 

 

 

 

(1) Assumes no exercise of the underwriters’ option to purchase additional common units. Please read “Summary—The Offering—Use of Proceeds” for a description of the impact of an exercise of the option on the common unit ownership.
(2) Does not include any common units that may be issued under the long term incentive plan our general partner intends to implement prior to the completion of this offering.

Because our general partner’s interest in us entitles it to control us without a right to any percentage of our distributions, our general partner will not receive ongoing distributions in respect of its general partner interest.

We expect to pay our distributions on or about the last day of each of February, May, August and November to holders of record on or about the 15th day of each such month. We will adjust the quarterly distribution for the period after the closing of this offering through                  , 2017, based on the actual length of such period.

Subordinated Units

Oasis will initially own all of our subordinated units. The principal difference between our common units and subordinated units is that, for any quarter during the subordination period, holders of the subordinated units are not entitled to receive any distribution from operating surplus until the common units have received the minimum quarterly distribution from operating surplus for such quarter plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. Subordinated units will not accrue arrearages. When the subordination period ends, all of the subordinated units will convert into an equal number of common units. Additionally, under certain circumstances, there is a provision for early termination of the subordination period.

To the extent we do not pay the minimum quarterly distribution from operating surplus on our common units, our common unitholders will not be entitled to receive such arrearage payments, except during the subordination period. To the extent we have distributable cash from operating surplus in any future quarter during the subordination period in excess of the amount necessary to pay the minimum quarterly distribution to holders of our common units, we will use this excess cash to pay any distribution arrearages on common units related to prior quarters before any cash distribution is made to holders of subordinated units. Please read “How We Make Distributions to Our Partners—Subordination Period.”

 

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In the sections that follow, we present in detail the basis for our belief that we will be able to fully fund our annualized minimum quarterly distribution of $         per unit for the twelve months ending June 30, 2018. In those sections, we present two tables, consisting of:

 

    “Unaudited Pro Forma Adjusted EBITDA and Distributable Cash Flow for the Year Ended December 31, 2016 and the Twelve Months Ended March 31, 2017,” in which we present the amount of our Adjusted EBITDA and distributable cash on a pro forma basis for the year ended December 31, 2016 and the twelve months ended March 31, 2017, derived from our unaudited pro forma condensed financial statements that are included elsewhere in this prospectus, as adjusted to give pro forma effect to, among other items, the contribution of the contributed assets to the partnership and the exclusion of the excluded assets, this offering and the related formation transactions and payments to our general partner for general and administrative expenses and public company expenses; and

 

    “Estimated EBITDA and Distributable Cash Flow for the Twelve Months Ending June 30, 2018,” in which we demonstrate our ability to generate sufficient distributable cash for us to pay the minimum quarterly distribution on all units for the twelve months ending June 30, 2018.

While the second quarter of 2017 is not complete, based on our internal preliminary results of operations, no events have occurred, nor do we currently expect any events to occur, that would affect our belief regarding our ability to generate sufficient distributable cash to pay the full minimum quarterly distribution on all of our outstanding units during the twelve months ending June 30, 2018.

Unaudited Pro Forma Adjusted EBITDA and Distributable Cash Flow for the Year Ended December 31, 2016 and the Twelve Months Ended March 31, 2017

If we had completed this offering and the related transactions on January 1, 2016, our unaudited pro forma distributable cash flow for the year ended December 31, 2016 and the twelve months ended March 31, 2017 would have been approximately $15.7 million and $19.2 million, respectively. This amount would not have been sufficient to pay the minimum quarterly distribution of $         per unit per quarter ($         per unit on an annualized basis) for the year ended December 31, 2016 or the twelve months ended March 31, 2017 on all of our common units. Specifically, this amount would only have been sufficient to allow us to pay a distribution of $         per unit per quarter ($         per unit on an annualized basis) and $             per unit per quarter ($             per unit on an annualized basis) on all of the common units, or only approximately    % and     % of the minimum quarterly distribution on all of our common units, during the year ended December 31, 2016 and the twelve months ended March 31, 2017, respectively. Because of these deficiencies, we would not have been able to pay distribution on the subordinated units during the year ended December 31, 2016 or the twelve months ended March 31, 2017.

We based the pro forma adjustments upon currently available information and specific estimates and assumptions. The pro forma amounts below do not purport to present our results of operations had this offering and related formation transactions been completed as of the date indicated. In addition, our distributable cash flow is primarily a cash accounting concept, while the audited historical financial statements of our Predecessor and the unaudited pro forma condensed financial statements included elsewhere in the prospectus have been prepared on an accrual basis. As a result, you should view the amount of pro forma distributable cash flow only as a general indication of the amount of distributable cash flow that we might have generated had we completed this offering on the date indicated. Our unaudited pro forma distributable cash flow should be read together with “Selected Historical and Pro Forma Financial Data,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the audited historical financial statements and unaudited pro forma condensed financial statements and the notes to those statements included elsewhere in this prospectus.

The following table illustrates, on a pro forma basis, for the year ended December 31, 2016 and the twelve months ended March 31, 2017, the amount of our distributable cash flow, assuming that this offering and the related formation transactions had been completed on January 1, 2016.

 

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Oasis Midstream Partners LP

Unaudited Pro Forma Distributable Cash Flow

 

    Year Ended
December 31, 2016
    Twelve Months Ended
March 31, 2017
 
   

(in millions)(1)

 

Revenues

   

Midstream services for Oasis

    $92.9     $ 110.7  
 

 

 

   

 

 

 

Total revenues

    92.9       110.7  
 

 

 

   

 

 

 

Operating expenses

   

Direct operating

    21.5       27.2  

Depreciation and amortization

    7.9       9.6  

General and administrative

    11.4       14.0  
 

 

 

   

 

 

 

Total operating expenses

    40.8       50.8  
 

 

 

   

 

 

 

Operating income

    52.1       59.9  
   

 

 

 

Other income (expense)

           

Interest expense(2)

    (1.1     (1.1
 

 

 

   

 

 

 

Net income

    51.0     $ 58.8  
 

 

 

   

 

 

 

Less:

   

Net income attributable to Oasis-retained non-controlling interests

    35.1       40.5  
 

 

 

   

 

 

 

Net income attributable to Partnership

    15.8       18.3  

Add:

   

Net income attributable to Oasis-retained non-controlling interests

    35.1       40.5  

Depreciation and amortization

    7.9       9.6  

Interest expense(2)

    1.1       1.1  

Other non-cash adjustments

    0.9       1.1  
 

 

 

   

 

 

 

Adjusted EBITDA(3)

    60.8       70.6  

Less:

   

Adjusted EBITDA attributable to Oasis-retained non-controlling interests

    40.6       46.7  
 

 

 

   

 

 

 

Adjusted EBITDA attributable to Partnership

    20.2       23.9  

Less:

   

Cash interest paid by Partnership(4)

    0.7       0.7  

Maintenance capital expenditures attributable to Partnership(5)

    1.3       1.5  

Expansion capital expenditures attributable to Partnership(6)

    86.8       69.6  

Additional public company general and administrative expenses to the Partnership(7)

    2.5       2.5  

Add:

   

Partnership borrowings to fund expansion capital expenditures

           

Contribution from Oasis to fund expansion capital expenditures(8)

    86.8       69.6  
 

 

 

   

 

 

 

Pro forma distributable cash flow attributable to Partnership

  $ 15.7     $ 19.2  
 

 

 

   

 

 

 

Pro forma distributions to:

   

Public common unitholders

   

Oasis

   

Common units

   

Subordinated units

   

Total distributions to Oasis

   
   

 

 

 

Total distributions

    $  
   

 

 

 

Excess of distributable cash flow over aggregate annualized minimum quarterly distribution

    $  
   

 

 

 

Percent of minimum quarterly distribution payable to common unitholders

          
   

 

 

 

Percent of minimum quarterly distribution payable to subordinated unitholders

          
   

 

 

 

 

(1) Components may not add to totals due to rounding.

 

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(2) Pro forma interest expense reflects the estimated non-cash amortization of the deferred financing costs related to our new revolving credit facility and estimated commitment fees on the unused portion of our new revolving credit facility (assuming no amounts have been drawn on the revolving credit facility).
(3) We define Adjusted EBITDA as earnings before interest expense (net of capitalized interest), income taxes, depreciation, amortization, impairment, stock based compensation expenses and other similar non-cash adjustments. Please read “Summary—Non-GAAP Financial Measure.”
(4) Reflects estimated cash interest relating to estimated commitment fees on the unused portion of our new revolving credit facility (assuming no amounts have been drawn on the revolving credit facility).
(5) Maintenance capital expenditures 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. The estimated maintenance capital expenditures attributable to Oasis’s retained interest are listed below:

 

    Year Ended
December 31, 2016
     Twelve Months Ended
March 31, 2017
 
   

(in millions)

 

Maintenance capital expenditures attributable to Partnership

  $ 1.3      $ 1.4  

Maintenance capital expenditures attributable to Oasis-retained non-controlling interest

  $ 2.4      $ 2.7  
 

 

 

    

 

 

 

Total maintenance capital expenditures attributable to our DevCos

  $ 3.7      $ 4.1  
 

 

 

    

 

 

 

 

(6) Expansion capital expenditures 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. Oasis recently constructed a significant portion of the midstream assets that will be contributed to us, which is reflected in the amount of the expansion capital expenditures for the year ended December 31, 2016 and the twelve months ended March 31, 2017. The estimated expansion capital expenditures attributable to Oasis’s retained interests are listed below:

 

    Year Ended
December 31, 2016
     Twelve Months Ended
March 31, 2017
 
   

(in millions)

 

Expansion capital expenditures attributable to Partnership

  $ 86.8      $ 69.6  

Expansion capital expenditures attributable to Oasis-retained non-controlling interest

  $ 79.5      $ 74.6  
 

 

 

    

 

 

 

Total expansion capital expenditures attributable to our DevCos

  $ 166.3      $ 144.2  
 

 

 

    

 

 

 

 

(7) Includes $2.5 million of general and administrative expenses we expect to incur annually as a result of becoming a publicly traded partnership.
(8) Expansion capital expenditures have been funded by Oasis directly or by choosing to forgo cash distributions.

 

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Estimated Adjusted EBITDA and Distributable Cash Flow for the Twelve Months Ending June 30, 2018

We forecast estimated Adjusted EBITDA and distributable cash flow attributable to Oasis Midstream Partners LP for the twelve months ending June 30, 2018 will be approximately $48.3 million and $42.7 million, respectively. In order to pay the aggregate annualized minimum quarterly distribution to all of our unitholders for the twelve months ending June 30, 2018, we must generate EBITDA and distributable cash flow of at least $         million and $         million, respectively.

We have not historically made public projections as to future operations, earnings or other results. However, management has prepared the forecast of estimated Adjusted EBITDA and distributable cash flow for the twelve months ending June 30, 2018, and related assumptions set forth below, to substantiate our belief that we will have sufficient Adjusted EBITDA and distributable cash flow to pay the aggregate annualized minimum quarterly distribution to all of our unitholders for the twelve months ending June 30, 2018. Please read “—Significant Forecast Assumptions.” Due to the rate of development of our assets and our dependence on Oasis’s exploration and production schedule for our revenue, our cash flows may vary from quarter to quarter. However, we believe that we will generate sufficient cash flow from operations to support the minimum quarterly distribution during each of the four quarters in the twelve months ending June 30, 2018. This forecast is a forward-looking statement and should be read together with our historical audited financial statements and unaudited pro forma condensed financial statements and the accompanying notes included elsewhere in this prospectus and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” This prospective financial information was not prepared with a view toward compliance with published guidelines of the Securities and Exchange Commission or the guidelines established by the American Institute of Certified Public Accountants for preparation or presentation of prospective financial information, but, in the view of our management, was prepared on a reasonable basis, reflects the best currently available estimates and judgments, and presents, to the best of management’s knowledge and belief, the assumptions on which we base our belief that we can generate sufficient Adjusted EBITDA and distributable cash flow to pay the minimum quarterly distribution to all unitholders and our general partner for the forecasted period. However, this information is not fact and should not be relied upon as being necessarily indicative of our future results, and readers of this prospectus are cautioned not to place undue reliance on the prospective financial information.

The prospective financial information included in this prospectus or any free writing prospectus has been prepared by, and is the responsibility of, our management. PricewaterhouseCoopers LLP has neither examined, compiled nor performed any procedures with respect to the accompanying prospective financial information and, accordingly, PricewaterhouseCoopers LLP does not express an opinion or any other form of assurance with respect thereto. The PricewaterhouseCoopers LLP report included in this offering document relates to our historical financial information. It does not extend to the prospective financial information and should not be read to do so.

When considering our financial forecast, you should keep in mind the risk factors and other cautionary statements under “Risk Factors.” Any of the risks discussed in this prospectus, to the extent they are realized, could cause our actual results of operations to vary significantly from those that would enable us to generate our estimated Adjusted EBITDA and distributable cash flow.

 

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We do not undertake any obligation to release publicly the results of any future revisions we may make to the forecast or to update this forecast to reflect events or circumstances after the date of this prospectus. Therefore, you are cautioned not to place undue reliance on this prospective financial information.

 

     Twelve
Months
Ending
June 30,
2018
    Three Months Ending  
       September 30,
2017
    December 31,
2017
    March 31,
2018
    June 30,
2018
 
     ($ in millions)(1)  

Revenues

          

Midstream Services Revenues

   $ 193.1     $ 43.2     $ 48.6     $ 48.0     $ 53.2  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total Revenue

   $ 193.1     $ 43.2     $ 48.6     $ 48.0     $ 53.2  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Expenses

          

Direct Operating

   $ 41.1     $ 9.9     $ 10.3     $ 10.2     $ 10.7  

General and Administrative(2)

     20.3       5.2       5.0       5.1       5.0  

Depreciation and Amortization

     16.5       4.0       4.1       4.1       4.3  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total Expenses

   $ 77.8     $ 19.1     $ 19.3     $ 19.4     $ 20.0  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Operating Income

   $ 115.3     $ 24.1     $ 29.3     $ 28.6     $ 33.2  

Interest Expense(3)

     0.8       0.2       0.2       0.2       0.2  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Income Before Income Tax Expense

   $ 114.5     $ 24.0     $ 29.1     $ 28.4     $ 33.0  

Income Tax Expense

                              
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net Income

   $ 114.5     $ 24.0     $ 29.1     $ 28.4     $ 33.0  

Less:

          

Net Income Attributable to Oasis-Retained Non-Controlling Interests

     (74.1     (15.8     (18.5     (18.1     (21.7
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net Income Attributable to Oasis Midstream Partners LP

   $ 40.4     $ 8.2     $ 10.6     $ 10.2     $ 11.4  

Add:

          

Net Income Attributable to Oasis-Retained Non-Controlling Interests

   $ 74.1     $ 15.8     $ 18.5     $ 18.1     $ 21.7  

Depreciation

     16.5       4.0       4.1       4.1       4.3  

Interest Expense(3)

     0.8       0.2       0.2       0.2       0.2  

Income Tax Expense

                              
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Adjusted EBITDA(4)

   $ 131.7     $ 28.1     $ 33.4     $ 32.7     $ 37.5  

Less:

          

Adjusted EBITDA Attributable to Oasis-Retained Non-Controlling Interests

   $ (83.4   $ (18.0   $ (20.8   $ (20.5   $ (24.1

Adjusted EBITDA Attributable to Oasis Midstream Partners LP(5)

   $ 48.3     $ 10.1     $ 12.5     $ 12.2     $ 13.4  

Less:

          

Cash Interest(6)

     (0.8     (0.2     (0.2     (0.2     (0.2

Estimated Maintenance Capital Expenditures(7)

     (4.9     (1.1     (0.8     (1.1     (1.8

Expansion Capital Expenditures(8)

     (8.9     (3.2     (0.6     (1.9     (3.3
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Add:

          

Borrowings to Fund Expansion Capital Expenditures

   $ 8.9     $ 3.2     $ 0.6     $ 1.9     $ 3.3  

Cash Used to Fund Expansion Capital Expenditures

                              

Estimated Distributable Cash Flow Attributable to Oasis Midstream Partners LP

   $ 42.7     $ 8.8     $ 11.6     $ 10.9     $ 11.4  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Distributions to Public Common Unitholders

   $     $     $     $     $  

Distributions to Oasis:

          

Common Units Held by Oasis

          

Subordinated Units Held by Oasis

          
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total Distributions to Oasis

   $     $     $     $     $  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Aggregate Quarterly Distributions

   $     $     $     $     $  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Excess Distributable Cash Flow Over Minimum Quarterly Distribution

   $              $              $              $              $           
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

(1) Components may not add to totals due to rounding.

 

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(2) Includes an incremental $2.5 million of estimated annual general and administrative expenses we expect to incur as a result of becoming a publicly traded partnership.
(3) Forecasted interest expense includes interest on amounts outstanding under our new revolving credit facility and commitment fees on the unused portion of our new revolving credit facility and excludes non-cash amortization of origination fees.
(4) We define Adjusted EBITDA as earnings before interest expense (net of capitalized interest), income taxes, depreciation, amortization, impairment, stock-based compensation expenses and other non-cash adjustments. Please read “Summary—Non-GAAP Financial Measure.”
(5) The following table reconciles net income attributable to Oasis-retained non-controlling interests to Adjusted EBITDA attributable to Oasis-retained non-controlling interests. These adjustments exclude both the costs of being a publicly traded partnership and interest expense at Oasis Midstream Partners LP.

 

     Twelve Months
Ended June 30,
2018
 
     (in millions)  

Net income attributable to Oasis-retained non-controlling interests

   $ 74.1  

Add:

  

Depreciation attributable to Oasis-retained non-controlling interests

     9.3  

Interest expense attributable to Oasis-retained non-controlling interests

  
  

 

 

 

Adjusted EBITDA attributable to Oasis-retained non-controlling interests

   $ 83.4  
  

 

 

 

 

(6) Reflects estimated cash interest relating to (i) interest on amounts outstanding under our new revolving credit facility and (ii) commitment fees on the unused portion of our new revolving credit facility.
(7) Represents estimated maintenance capital expenditures attributable to the Partnership. The estimated maintenance capital expenditures for Oasis-retained non-controlling interests is shown in the following table.

 

     Twelve Months
Ended June 30,
2018
 
     (in millions)  

Maintenance capital expenditures attributable to Partnership

   $ 4.9  

Maintenance capital expenditures attributable to Oasis-retained non-controlling interests

     11.0  
  

 

 

 

Total maintenance capital expenditures attributable to our DevCos

   $ 15.9  
  

 

 

 

 

(8) Represents estimated expansion capital expenditures attributable to the Partnership. The total estimated expansion capital expenditures for Oasis-retained non-controlling interests is shown in the following table.

 

     Twelve Months Ended June 30, 2018  

Expansion Capital Expenditures

   Expansion
Capital
Expenditures
Attributable to
Oasis Midstream
Partners LP
     Expansion
Capital
Expenditures
Attributable to
Oasis’s Non-
Controlling
Interest
     Total
Expansion
Capital
Expenditures
 
            (in millions)         

Bighorn DevCo

   $      $      $  

Bobcat DevCo

     3.8        33.9        37.6  

Beartooth DevCo

     5.2        9.6        14.8  
  

 

 

    

 

 

    

 

 

 

Total Expansion Capital Expenditures

   $ 8.9      $ 43.5      $ 52.4  
  

 

 

    

 

 

    

 

 

 

 

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Significant Forecast Assumptions

The forecast has been prepared by and is the responsibility of management. The forecast reflects our judgment, as of the date of this prospectus, of conditions we expect to exist and the course of action we expect to take during the twelve months ending June 30, 2018. We believe our actual results of operations will approximate those reflected in our forecast, but we can give no assurance that our forecasted results will be achieved. There will likely be differences between our forecast and our actual results, and those differences could be material. If the forecasted results are not achieved, we may not be able to make cash distributions on our common units at the minimum quarterly distribution rate or at all.

In addition, although Oasis has dedicated certain acreage to us under each of our commercial agreements with Oasis, these commercial agreements do not contain minimum volume commitments. Accordingly, if commodity prices decline substantially for a prolonged period, Oasis has the ability to substantially reduce its drilling and completion expenditures, which would decrease our throughput volumes from Oasis and related revenue streams under our commercial agreements.

General Considerations

Our Predecessor’s historical results of operations include all of the results of operations of Oasis Midstream Partners LP Predecessor on a 100% basis, which includes 100% of the results of each of our DevCos, in which we own percentages varying from 10% to 100%. See “Business—Our Assets.” In connection with the completion of this offering, Oasis will contribute to us a 100% controlling interest in Bighorn DevCo, a 10% controlling interest in Bobcat DevCo and a 35% controlling interest in Beartooth DevCo. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Items Affecting Comparability of Our Financial Condition and Results of Operations” and “Certain Relationships and Related Party Transactions—Agreements with Affiliates in Connection with the Transactions—Services and Secondment Agreement.” Substantially all of our revenues will be generated through long-term, fixed-fee contracts pursuant to which we provide midstream services for Oasis.

Results and Volumes

The following table summarizes the pro forma volumes, operating income and depreciation and amortization for our midstream services, which include 100% of the results of each of our DevCos, for the year ended December 31, 2016 and the three months ended March 31, 2017, as well as our forecast regarding those same amounts for the twelve months ending June 30, 2018. Operating income for our DevCos does not include the $2.5 million of estimated annual general and administrative expenses we expect to incur as a result of becoming a publicly traded partnership.

 

     Pro Forma
Year Ended
December 31,
2016
     Pro Forma
Three Months
Ended
March 31, 2017
     Forecasted
Twelve Months
Ending
June 30, 2018
 

Bighorn DevCo

        

Crude oil services volumes (Bopd)

     4,531        31,690        29,972  

Natural gas services volumes (Mscfpd)

     10,546        56,088        72,845  

Operating income ($ in millions)

   $ 1.1      $ 3.4      $ 24.3  

Depreciation and amortization ($ in millions)

   $ 1.0      $ 1.0      $ 4.4  

Bobcat DevCo

        

Crude oil services volumes (Bopd)

     2,533        20,085        28,544  

Natural gas services volumes (Mscfpd)

     19,901        70,026        80,369  

Water services volumes (Bowpd)

     10,392        27,740        33,764  

Operating income ($ in millions)

   $ 8.1      $ 9.9      $ 53.5  

Depreciation and amortization ($ in millions)

   $ 1.5      $ 0.9      $ 5.9  

Beartooth DevCo

        

Water services volumes (Bowpd)

     76,546        67,333        85,582  

Operating income ($ in millions)

   $ 42.8      $ 7.1      $ 40.0  

Depreciation and amortization ($ in millions)

   $ 5.4      $ 1.3      $ 6.2  

 

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Revenue

We estimate total revenue for the twelve months ending June 30, 2018 will be approximately $193.1 million, compared to approximately $92.9 million for the pro forma year ended December 31, 2016 and $110.7 million for the pro forma twelve months ended March 31, 2017, primarily due to increased throughput on our gathering systems and the startup of our full service midstream system providing compression, processing and gas lift services in the Wild Basin area in late 2016.

Throughput

 

    In Bighorn DevCo, we estimate daily throughput of crude oil and natural gas services volumes for the twelve months ending June 30, 2018 will be 29,972 Bopd and 72,845 Mscfpd, respectively, compared to 4,531 Bopd and 10,546 Mscfpd for the pro forma year ended December 31, 2016. The difference is primarily due to incremental well completions and the startup of our full service midstream system in the Wild Basin area in late 2016.

 

    In Bobcat DevCo, we estimate daily throughput of crude oil, natural gas and water services volumes for the twelve months ending June 30, 2018 will be 28,544 Bopd, 80,369 Mscfpd and 33,764 Bowpd, respectively, compared to 2,533 Bopd, 19,901 Mscfpd and 10,392 Bowpd for the pro forma year ended December 31, 2016. The difference is primarily due to incremental well completions and the startup of our full service midstream system in the Wild Basin area in late 2016.

 

    In Beartooth DevCo, we estimate daily throughput of water services volumes for the twelve months ending June 30, 2018 will be 85,582 Bowpd compared to 76,546 Bowpd for the pro forma year ended December 31, 2016. The difference is primarily due to increased well completions on our dedicated acreage outside of Wild Basin consistent with Oasis’s development plan.

Our forecasted service volumes and operating income are based on Oasis’s drilling and development plan, adjusted by management for operational and other risks, as well as our commercial agreements with Oasis. The forecasted volumes include volumes associated with Oasis’s net entitlement in its operated properties, as well as volumes that Oasis has historically and expects to continue to purchase from its working interest and royalty owners and other third parties. Our actual service volumes may deviate from the forecast based on, among other things, the effects of changing commodity prices and production margins, Oasis’s and other third parties’ ability to successfully increase their respective production and the inherent uncertainties of future production rates, and there is no assurance that Oasis’s production outlook will not change during the forecast period or in subsequent periods. Please read “Risk Factors—Risks Related to Our Business.”

Direct Operating Expense

We estimate our direct operating expense for the twelve months ending June 30, 2018 will be approximately $41.1 million, compared to approximately $21.5 million for the pro forma year ended December 31, 2016 and $27.2 million for the pro forma twelve months ended March 31, 2017. The change in direct operating expense is primarily due to our significantly higher operating levels resulting in higher:

 

    crude oil, natural gas and water services volumes on our dedicated acreage;

 

    maintenance and contract costs;

 

    regulatory and compliance costs; and

 

    operating costs associated with the operation of a full suite of midstream services providing compression, processing and gas lift services in the Wild Basin area.

General and Administrative Expenses

Our general and administrative expenses will consist of (i) direct general and administrative expenses incurred by us and (ii) reimbursements to Oasis for general and administrative expenses incurred by Oasis for the

 

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provision of services as part of the services and secondment agreement. Please see “Certain Relationships and Related Party Transactions—Agreements with Affiliates in Connection with the Transactions—Services and Secondment Agreement.”

We estimate total general and administrative expenses for the twelve months ended June 30, 2018 will be approximately $20.3 million as compared to approximately $11.4 million for the pro forma year ended December 31, 2016 and $14.0 million for the pro forma twelve months ended March 31, 2017. The forecast period includes approximately $2.5 million of incremental general and administrative expenses related to us becoming a publicly traded partnership. The remaining projected increase in general and administrative expenses relates to increased personnel and administrative expenses resulting from our projected growth.

Depreciation

We estimate depreciation for the twelve months ended June 30, 2018 will be approximately $16.5 million as compared to approximately $7.9 million for the pro forma year ended December 31, 2016 and $9.6 million for the pro forma twelve months ended March 31, 2017. The increase in expected depreciation is primarily attributable to the effect of depreciation on newly constructed and to be constructed infrastructure during the twelve months ended June 30, 2018.

Capital Expenditures

The midstream energy business is capital intensive; thus, our operations are expected to require capital investments to maintain, expand, upgrade or enhance our existing operations. Our capital requirements are expected to be 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.

Because Oasis has retained a non-controlling interest in each of the DevCos that hold our assets, Oasis will be required to fund its allocable portion of our maintenance and expansion capital expenditures.

Maintenance Capital Expenditures

We estimate that maintenance capital expenditures will be $15.9 million ($4.9 million net to our ownership interests in our DevCos) for the twelve months ending June 30, 2018. We expect to fund our allocated portion of these maintenance capital expenditures with cash generated by our operations. Because our midstream

 

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systems are relatively new, having been substantially built within the last three years, we believe that the capital expenditures necessary to repair, refurbish and replace pipelines, to maintain equipment reliability, integrity and safety and to comply with environmental laws and regulations during the twelve months ending June 30, 2018 will be relatively low. The majority of our maintenance capital expenditures included in the forecast period represent that portion of our estimated capital expenditures associated with the connection of new wells to our gathering systems that we believe will be necessary to maintain, over the long term, system operating capacity, operating income or revenue.

Expansion Capital Expenditures

We estimate that expansion capital expenditures for the twelve months ending June 30, 2018 will be $52.4 million ($8.9 million net to our ownership interests in our DevCos). During the twelve months ending June 30, 2018, we have assumed that we will fund our allocated portion of expansion capital expenditures with borrowings under our new revolving credit facility. In general, our expansion capital expenditures are necessary to increase the size and scope of our midstream infrastructure in order to continue servicing Oasis’s drilling and completion schedule and increasing production on our dedicated acreage. A majority of Oasis’s planned well completions and production growth on our dedicated acreage during the twelve months ending June 30, 2018 will drive our need for expansion capital expenditures. These expansion capital expenditures are primarily comprised of the following expansion capital projects that we intend to pursue during the twelve months ending June 30, 2018:

 

    Bighorn DevCo: We do not expect to incur any expansion capital expenditures for the twelve months ending June 30, 2018 because the assets held by Bighorn DevCo are complete and fully operational.

 

    Bobcat DevCo: We expect to spend approximately $37.6 million in expansion capital expenditures ($3.8 million net to our ownership interest) primarily related to the continued expansion of our gathering systems, additional compression facilities and incremental SWD wells.

 

    Beartooth DevCo: We expect to spend approximately $14.8 million in expansion capital expenditures ($5.2 million net to our ownership interest) primarily related to the continued expansion of our gathering systems, incremental SWD wells and the portion of our estimated capital expenditures associated with the connection of new wells to our gathering systems that we believe will be necessary to increase system operating capacity, operating income or revenue over the long term.

Regulatory, Industry and Economic Factors

Our forecast of Adjusted EBITDA and Distributable Cash Flow for the twelve months ended June 30, 2018 is also based on the following regulatory, industry and economic factors:

 

    Oasis will not default under our commercial agreements or reduce, suspend or terminate its obligations, nor will any events occur that would be deemed a force majeure event, under such agreements;

 

    there will not be any new federal, state or location regulation, or any interpretations or application of existing regulation, of the portions of the midstream energy industry in which we operate that will be materially adverse to our business;

 

    there will not be any material accidents, weather-related incidents, unscheduled downtime or similar unanticipated events with respect to our assets or Oasis’s development plan;

 

    there will not be a shortage of skilled labor; and

 

    there will not be any material adverse changes in the midstream energy industry, commodity prices, capital markets or overall economic conditions.

 

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HOW WE MAKE DISTRIBUTIONS TO OUR PARTNERS

General

Cash Distribution Policy

Our partnership agreement provides that our general partner will make a determination as to whether to make a distribution, but does not require us to pay distributions at any time or in any amount. Instead, the board of directors of our general partner will adopt a cash distribution policy to be effective as of the closing of this offering that will set forth our general partner’s intention with respect to the distributions to be made to unitholders. Pursuant to our cash distribution policy, within 60 days after the end of each quarter, beginning with the quarter ending                 , 2017, we intend to distribute to the holders of common and subordinated units on a quarterly basis at least the minimum quarterly distribution of $         per unit, or $         on an annualized basis, to the extent we have sufficient cash after establishment of cash reserves and payment of fees and expenses, including payments to our general partner and its affiliates. We will prorate the distribution for the period after the closing of the offering through                 , 2017.

The board of directors of our general partner may change the foregoing distribution policy at any time and from time to time, and even if our cash distribution policy is not modified or revoked the amount of distributions paid under our policy and the decision to make any distribution is determined by our general partner. Our partnership agreement does not contain a requirement for us to pay distributions to our unitholders, and there is no guarantee that we will pay the minimum quarterly distribution, or any distribution, on the units in any quarter. However, our partnership agreement does contain provisions intended to motivate our general partner to make steady, increasing and sustainable distributions over time.

Set forth below is a summary of the significant provisions of our partnership agreement that relate to cash distributions.

Operating Surplus and Capital Surplus

General

Any distributions we make will be characterized as made from “operating surplus” or “capital surplus.” Distributions from operating surplus are made differently than cash distributions that we would make from capital surplus. Operating surplus distributions will be made to our unitholders and, if we make quarterly distributions above the first target distribution level described below, to the holder of our incentive distribution rights. We do not anticipate that we will make any distributions from capital surplus. In such an event, however, any capital surplus distribution would be made pro rata to all unitholders, but the incentive distribution rights would generally not participate in any capital surplus distributions. Any distribution from capital surplus would result in a reduction of the minimum quarterly distribution and target distribution levels and, if we reduce the minimum quarterly distribution to zero and eliminate any unpaid arrearages, thereafter capital surplus would be distributed as if it were operating surplus and the incentive distribution rights would thereafter be entitled to participate in such distributions. Please see “—Distributions from Capital Surplus.”

Operating Surplus

We define operating surplus as:

 

    $         million (as described below); plus

 

    all of our cash receipts after the closing of this offering, excluding cash from interim capital transactions (as defined below) and provided that cash receipts from the termination of any hedge contract prior to its stipulated settlement or termination date will be included in equal quarterly installments over the remaining scheduled life of such hedge contract had it not been terminated; plus

 

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    cash distributions paid in respect of equity issued (including incremental distributions on incentive distribution rights), other than equity issued in this offering, to finance all or a portion of expansion capital expenditures in respect of the period that commences when we enter into a binding obligation for the acquisition, construction, development or expansion and ending on the earlier to occur of the date any acquisition, construction, development or expansion commences commercial service and the date that it is disposed of or abandoned; plus

 

    cash distributions paid in respect of equity issued (including incremental distributions on incentive distribution rights) to pay the construction period interest on debt incurred, or to pay construction period distributions on equity issued, to finance the expansion capital expenditures referred to above, in each case, in respect of the period that commences when we enter into a binding obligation for the acquisition, construction, development or expansion and ending on the earlier to occur of the date any acquisition, construction, development or expansion commences commercial service and the date that it is disposed of or abandoned; less

 

    all of our operating expenditures (as defined below), which includes maintenance capital expenditures after the closing of this offering; less

 

    the amount of cash reserves established by our general partner to provide funds for future operating expenditures; less

 

    all working capital borrowings not repaid within twelve months after having been incurred, or repaid within such twelve-month period with the proceeds of additional working capital borrowings; less

 

    any cash loss realized on disposition of an investment capital expenditure.

Disbursements made, cash received (including working capital borrowings) or cash reserves established, increased or reduced after the end of a period but on or before the date on which cash or cash equivalents will be distributed with respect to such period shall be deemed to have been made, received, established, increased or reduced, for purposes of determining operating surplus, within such period if our general partner so determines. Furthermore, cash received from an interest in an entity for which we account using the equity method will not be included to the extent it exceeds our proportionate share of that entity’s operating surplus (calculated as if the definition of operating surplus applied to such entity from the date of our acquisition of such an interest without any basket similar to that described in the first bullet above). Operating surplus does not reflect cash generated by our operations. For example, it includes a basket of $         million that will enable us, if we choose, to distribute as operating surplus cash we receive in the future from non-operating sources such as asset sales, issuances of securities and long-term borrowings that would otherwise be distributed as capital surplus. In addition, the effect of including, as described above, certain cash distributions on equity interests in operating surplus will be to increase operating surplus by the amount of any such cash distributions. As a result, we may also distribute as operating surplus up to the amount of any such cash that we receive from non-operating sources.

The proceeds of working capital borrowings increase operating surplus, and repayments of working capital borrowings are generally operating expenditures, as described below, and thus reduce operating surplus when made. However, if a working capital borrowing is not repaid during the twelve-month period following the borrowing, it will be deducted from operating surplus at the end of such period, thus decreasing operating surplus at such time. When such working capital borrowing is in fact repaid, it will be excluded from operating expenditures because operating surplus will have been previously reduced by the deduction.

We define operating expenditures in our partnership agreement, and it generally means all of our cash expenditures, including, but not limited to, taxes, reimbursement of expenses to our general partner or its affiliates, payments made under interest rate hedge agreements or commodity hedge agreements (provided that (1) with respect to amounts paid in connection with the initial purchase of an interest rate hedge contract or a commodity hedge contract, such amounts will be amortized over the life of the applicable interest rate hedge contract or commodity hedge contract and (2) payments made in connection with the termination of any interest rate hedge contract or commodity hedge contract prior to the expiration of its stipulated settlement or termination

 

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date will be included in operating expenditures in equal quarterly installments over the remaining scheduled life of such interest rate hedge contract or commodity hedge contract), officer compensation, repayment of working capital borrowings, interest on indebtedness and capital expenditures (as discussed in further detail below). However, operating expenditures will not include:

 

    repayment of working capital borrowings deducted from operating surplus pursuant to the penultimate bullet point of the definition of operating surplus above when such repayment actually occurs;

 

    payments (including prepayments and prepayment penalties and the purchase price of indebtedness that is repurchased and cancelled) of principal of and premium on indebtedness, other than working capital borrowings;

 

    expansion capital expenditures;

 

    investment capital expenditures;

 

    payment of transaction expenses relating to interim capital transactions;

 

    distributions to our partners (including distributions in respect of our incentive distribution rights); or

 

    repurchases of equity interests except to fund obligations under employee benefit plans.

Capital Surplus

Capital surplus is defined in our partnership agreement as any cash distributed in excess of our operating surplus. Accordingly, capital surplus would generally be generated only by the following (which we refer to as “interim capital transactions”):

 

    borrowings other than working capital borrowings;

 

    sales of our equity interests; and

 

    sales or other dispositions of assets for cash, other than inventory, accounts receivable and other assets sold in the ordinary course of business or as part of normal retirement or replacement of assets.

Characterization of Cash Distributions

Our partnership agreement provides that we treat all cash distributed as coming from operating surplus until the sum of all cash distributed since the closing of this offering (other than any distributions of proceeds of this offering) equals the operating surplus from the closing of this offering. Our partnership agreement provides that we treat any amount distributed in excess of operating surplus, regardless of its source, as distributions of capital surplus. We do not anticipate that we will make any distributions from capital surplus.

Capital Expenditures

Maintenance capital expenditures reduce operating surplus, but expansion capital expenditures and investment capital expenditures do not. Maintenance capital expenditures 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.

 

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Expansion capital expenditures 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 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 will also include interest (and related fees) on debt incurred and distributions on equity issued (including incremental distributions on incentive distribution rights) to finance all or any portion of such acquisition, development or expansion in respect of the period that commences when we enter into a binding obligation for the acquisition, construction, development or expansion and ending on the earlier to occur of the date any acquisition, construction, development or expansion commences commercial service and the date that it is disposed of or abandoned. Expenditures made solely for investment purposes will not be considered expansion capital expenditures.

Investment capital expenditures are those capital expenditures, including transaction expenses, which are neither maintenance capital expenditures nor expansion capital expenditures. Investment capital expenditures largely will consist of capital expenditures made for investment purposes. Examples of investment capital expenditures include traditional capital expenditures for investment purposes, such as purchases of securities, as well as other capital expenditures that might be made in lieu of such traditional investment capital expenditures, such as the acquisition of an asset for investment purposes or development of assets that are in excess of the maintenance of existing system operating capacity or operating income, but which are not expected to expand, for more than the short term, system operating capacity or operating income.

As described above, neither investment capital expenditures nor expansion capital expenditures are operating expenditures, and thus will not reduce operating surplus. Because expansion capital expenditures include interest payments (and related fees) on debt incurred to finance all or a portion of an acquisition, development or expansion in respect of a period that begins when we enter into a binding obligation for an acquisition, construction, development or expansion and ending on the earlier to occur of the date on which such acquisition, construction, development or expansion commences commercial service and the date that is abandoned or disposed of, such interest payments also do not reduce operating surplus. Losses on disposition of an investment capital expenditure will reduce operating surplus when realized and cash receipts from an investment capital expenditure will be treated as a cash receipt for purposes of calculating operating surplus only to the extent the cash receipt is a return on principal.

Cash expenditures that are made in part for maintenance capital purposes, investment capital purposes or expansion capital purposes will be allocated as maintenance capital expenditures, investment capital expenditures or expansion capital expenditures by our general partner.

Subordination Period

General

Our partnership agreement provides that, during the subordination period (described below), the common units will have the right to receive distributions from operating surplus each quarter in an amount equal to $ per common unit, which amount is defined in our partnership agreement as 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 from operating surplus may be made on the subordinated units. These units are deemed “subordinated” because for a period of time, referred to as the subordination period, the subordinated units will not be entitled to receive any distributions from operating surplus for any quarter until the common units have received the minimum quarterly distribution from operating surplus for such quarter plus any arrearages in the

 

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payment of the minimum quarterly distribution from prior quarters. Furthermore, no arrearages will be paid on the subordinated units. The practical effect of the subordinated units is to increase the likelihood that during the subordination period there will be sufficient cash from operating surplus to pay the minimum quarterly distribution on the common units.

Determination of Subordination Period

Oasis will initially own all of our subordinated units. Except as described below, the subordination period will begin on the closing date of this offering and will expire on the first business day after the distribution to unitholders in respect of any quarter, beginning with the quarter ending                 , 20     , if each of the following has occurred:

 

    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 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 described below) equaled or exceeded the sum of the minimum quarterly distribution multiplied by the total number of common 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.

For the period after the closing of this offering through                 , 2017, our partnership agreement will prorate the minimum quarterly distribution based on the actual length of the period, and use such prorated distribution for all purposes, including in determining whether the test described above has been satisfied.

Early Termination of Subordination Period

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        &n