S-1

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.

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

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

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

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.

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. ☒

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.

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.

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.

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.

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

Index to Financial Statements

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.”

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.

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.

Index to Financial Statements

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

Index to Financial Statements

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.

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

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.

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.

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

Index to Financial Statements

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.

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.

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

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

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.

Index to Financial Statements

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.

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

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.

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.

Index to Financial Statements

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.

Index to Financial Statements

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.

Index to Financial Statements

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

Index to Financial Statements

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

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

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.

Index to Financial Statements

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;

Index to Financial Statements

•

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.

Index to Financial Statements

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

Index to Financial Statements

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.

Index to Financial Statements

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.

Index to Financial Statements

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

Index to Financial Statements

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.

Index to Financial Statements

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.”

Index to Financial Statements

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.”

Index to Financial Statements

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.”

Index to Financial Statements

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

Index to Financial Statements


		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

Index to Financial Statements


		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

Index to Financial Statements

Index to Financial Statements

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.

Index to Financial Statements

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.

Index to Financial Statements

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

Index to Financial Statements

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.

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:

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,

Index to Financial Statements

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:

Index to Financial Statements

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

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.

Index to Financial Statements

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:

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.

Index to Financial Statements

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

Index to Financial Statements

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:

Index to Financial Statements

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

Index to Financial Statements

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

Index to Financial Statements

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:

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

Index to Financial Statements

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.

Index to Financial Statements

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.

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

Index to Financial Statements

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.

Index to Financial Statements

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,

Index to Financial Statements

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:

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.

Index to Financial Statements

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:

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 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.

Index to Financial Statements

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

Index to Financial Statements

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;

Index to Financial Statements

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.

Index to Financial Statements

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

Index to Financial Statements

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.

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

Index to Financial Statements

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

Index to Financial Statements

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.

Index to Financial Statements

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

Index to Financial Statements

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:

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:

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.

Index to Financial Statements

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

Index to Financial Statements

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.

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.”

Index to Financial Statements

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.

Index to Financial Statements

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:

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:

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.

Index to Financial Statements

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

Index to Financial Statements

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:

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.

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

Index to Financial Statements

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:

Index to Financial Statements

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.

Index to Financial Statements

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:

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.”

Index to Financial Statements

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:

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

Index to Financial Statements

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.

Index to Financial Statements

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.

Index to Financial Statements

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.”

Index to Financial Statements

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:

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,

Index to Financial Statements

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:

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

Index to Financial Statements

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:

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

Index to Financial Statements

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.

Index to Financial Statements

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.

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.

Index to Financial Statements

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

Index to Financial Statements

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

Index to Financial Statements

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 (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.”

Index to Financial Statements

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

Index to Financial Statements

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.

Index to Financial 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:

Index to Financial Statements

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.

Index to Financial Statements

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.

Index to Financial Statements

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

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.”

Index to Financial Statements

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:

Index to Financial Statements

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:

Index to Financial Statements

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.

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:

Index to Financial Statements

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.

Index to Financial Statements

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:

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.

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.”

Index to Financial Statements

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:

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.

Index to Financial Statements

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.

Index to Financial Statements

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.

Index to Financial Statements

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.

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.

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.

Index to Financial Statements

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.

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.”

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:

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

Index to Financial Statements

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.

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.

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:

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.

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

Index to Financial Statements

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.

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:

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:

Index to Financial Statements

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.

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.”

Index to Financial Statements

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

Index to Financial Statements

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:

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”):

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.

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.

Index to Financial Statements

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.

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

Index to Financial Statements

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.

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 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.

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 , 20 , if each of the following has occurred:

When the subordination period ends, each outstanding subordinated unit will convert into one common unit, which will then participate pro-rata with the other common units in distributions.

Index to Financial Statements

Adjusted operating surplus is intended to generally reflect the cash generated from operations during a particular period and therefore excludes net increases in working capital borrowings and net drawdowns of reserves of cash generated in prior periods if not utilized to pay expenses during that period. Adjusted operating surplus for any period consists of:

Any disbursements received, cash received (including working capital borrowings) or cash reserves established, increased or reduced after the end of a period that the general partner determines to include in operating surplus for such period shall also be deemed to have been made, received or established, increased or reduced in such period for purposes of determining adjusted operating surplus for such period.

If we make distributions of cash from operating surplus for any quarter ending before the end of the subordination period, our partnership agreement requires that we make the distribution in the following manner:

If we make distributions of cash from operating surplus for any quarter ending after the subordination period, our partnership agreement requires that we make the distribution in the following manner:

Our general partner owns a non-economic general partner interest in us, which does not entitle it to receive cash distributions. However, our general partner may in the future own common units or other equity interests in us and will be entitled to receive distributions on any such interests.

Index to Financial Statements

Incentive distribution rights represent the right to receive increasing percentages (15%, 25% and 50%) of quarterly distributions from operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved. Our general partner currently holds the incentive distribution rights, but may transfer these rights separately from its general partner interest.

then we will make additional distributions from operating surplus for that quarter among the unitholders and the holders of the incentive distribution rights in the following manner:

The following table illustrates the percentage allocations of distributions from operating surplus between the unitholders and the holders of our incentive distribution rights based on the specified target distribution levels. The amounts set forth under the column heading “Marginal Percentage Interest in Distributions” are the percentage interests of the holders of our incentive distribution rights and the unitholders in any distributions from operating surplus we distribute up to and including the corresponding amount in the column “Total Quarterly Distribution Per Unit.” The percentage interests shown for our unitholders and the holders of our incentive distribution rights for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests set forth below assume there are no arrearages on common units.

Index to Financial Statements

The holder of our incentive distribution rights has the right under our partnership agreement to elect to relinquish the right to receive incentive distribution payments based on the initial target distribution levels and to reset, at higher levels, the target distribution levels upon which the incentive distribution payments would be set. If our general partner transfers all or a portion of the incentive distribution rights in the future, then the holder or holders of a majority of our incentive distribution rights will be entitled to exercise this right. The following discussion assumes that our general partner holds all of the incentive distribution rights at the time that a reset election is made.

The right to reset the target distribution levels upon which the incentive distributions are based may be exercised, without approval of our unitholders or the conflicts committee of our general partner, at any time when there are no subordinated units outstanding and we have made cash distributions to the holders of the incentive distribution rights at the highest level of incentive distribution for the prior four consecutive fiscal quarters. The reset target distribution levels will be higher than the target distributions levels prior to the reset such that there will be no incentive distributions paid under the reset target distribution levels until cash distributions per unit following the reset event increase as described below. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would otherwise not be sufficiently accretive to cash distributions per common unit, taking into account the existing levels of incentive distribution payments being made.

In connection with the resetting of the target distribution levels and the corresponding relinquishment by our general partner of incentive distribution payments based on the target cash distributions prior to the reset, our general partner will be entitled to receive a number of newly issued common units based on the formula described below that takes into account the “cash parity” value of the cash distributions related to the incentive distribution rights for the quarter prior to the reset event as compared to the cash distribution per common unit in such quarter.

The number of common units to be issued in connection with a resetting of the minimum quarterly distribution amount and the target distribution levels would equal the quotient determined by dividing (x) the amount of cash distributions received in respect of the incentive distribution rights for the fiscal quarter ended immediately prior to the date of such reset election by (y) the amount of cash distributed per common unit with respect to such quarter.

Following a reset election, a baseline minimum quarterly distribution amount will be calculated as an amount equal to the cash distribution amount per unit for the fiscal quarter immediately preceding the reset election (which amount we refer to as the “reset minimum quarterly distribution”) and the target distribution levels will be reset to be correspondingly higher such that we would make distributions from operating surplus for each quarter thereafter as follows:

Because a reset election can only occur after the subordination period expires, the reset minimum quarterly distribution will have no significance except as a baseline for the target distribution levels.

Index to Financial Statements

The following table illustrates the percentage allocation of distributions from operating surplus between the unitholders and the holders of our incentive distribution rights at various distribution levels (1) pursuant to the distribution provisions of our partnership agreement in effect at the closing of this offering, as well as (2) following a hypothetical reset of the target distribution levels based on the assumption that the quarterly distribution amount per common unit during the fiscal quarter immediately preceding the reset election was $ .

The following table illustrates the total amount of distributions from operating surplus that would be distributed to the unitholders and the holders of incentive distribution rights, based on the amount distributed for the quarter immediately prior to the reset. The table assumes that immediately prior to the reset there would be common units outstanding and the distribution to each common unit would be $ for the quarter prior to the reset.

Index to Financial Statements

The following table illustrates the total amount of distributions from operating surplus that would be distributed to the unitholders and the holders of incentive distribution rights, with respect to the quarter in which the reset occurs. The table reflects that, as a result of the reset, there would be common units outstanding and the distribution to each common unit would be $ . The number of common units to be issued upon the reset was calculated by dividing (1) the amount received in respect of the incentive distribution rights for the quarter prior to the reset as shown in the table above, or $ , by (2) the cash distributed on each common unit for the quarter prior to the reset as shown in the table above, or $ .

The holders of our incentive distribution rights will be entitled to cause the target distribution levels to be reset on more than one occasion. There are no restrictions on the ability of holders of our incentive distribution rights to exercise the reset right multiple times, but the requirements for exercise must be met each time. Because one of the requirements is that we make cash distributions in excess of the then-applicable third target distribution for the prior four consecutive fiscal quarters, a minimum of four quarters must elapse between each reset.

Our partnership agreement requires that we make distributions from capital surplus, if any, in the following manner:

Our partnership agreement treats a distribution from capital surplus as the repayment of the initial unit price from this initial public offering, which is a return of capital. Each time a distribution from capital surplus is made, the minimum quarterly distribution and the target distribution levels will be reduced in the same proportion as the distribution from capital surplus to the fair market value of the common units prior to the announcement of the distribution. Because distributions from capital surplus will reduce the minimum quarterly distribution and target distribution levels after any of these distributions are made, it may be easier for our general partner to receive incentive distributions and for the subordinated units to convert into common units. However, any distribution from capital surplus before the minimum quarterly distribution is reduced to zero cannot be applied to the payment of the minimum quarterly distribution or any arrearages.

Index to Financial Statements

Once we reduce the minimum quarterly distribution and target distribution levels to zero and eliminate any arrearages, all future distributions will be made such that 50% is paid to all unitholders, pro rata, and 50% is paid to the holder or holders of incentive distribution rights, pro rata.

Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels

In addition to adjusting the minimum quarterly distribution and target distribution levels to reflect a distribution from capital surplus, if we combine our common units into fewer common units or subdivide our common units into a greater number of common units, our partnership agreement specifies that the following items will be proportionately adjusted:

For example, if a two-for-one split of the common units should occur, the minimum quarterly distribution, the target distribution levels and the initial unit price would each be reduced to 50% of its initial level. If we combine our common units into a lesser number of units or subdivide our common units into a greater number of units, we will combine or subdivide our subordinated units using the same ratio applied to the common units. We will not make any adjustment by reason of the issuance of additional units for cash or property.

In addition, if, as a result of a change in law or interpretation thereof, we or any of our subsidiaries is treated as an association taxable as a corporation or is otherwise subject to additional taxation as an entity for U.S. federal, state, local or non-U.S. income or withholding tax purposes, our general partner may, in its sole discretion, reduce the minimum quarterly distribution and the target distribution levels for each quarter by multiplying each distribution level by a fraction, the numerator of which is cash for that quarter (after deducting our general partner’s estimate of our additional aggregate liability for the quarter for such income and withholding taxes payable by reason of such change in law or interpretation) and the denominator of which is the sum of (1) cash for that quarter, plus (2) our general partner’s estimate of our additional aggregate liability for the quarter for such income and withholding taxes payable by reason of such change in law or interpretation thereof.

If we dissolve in accordance with the partnership agreement, we will sell or otherwise dispose of our assets in a process called liquidation. We will first apply the proceeds of liquidation to the payment of our creditors. We will distribute any remaining proceeds to the unitholders and the holders of the incentive distribution rights, in accordance with their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of our assets in liquidation.

The allocations of gain and loss upon liquidation are intended, to the extent possible, to entitle the holders of units to a repayment of the initial value contributed by unitholders for their units in this offering, which we refer to as the “initial unit price” for each unit. The allocations of gain and loss upon liquidation are also intended, to the extent possible, to entitle the holders of common units to a preference over the holders of subordinated units upon our liquidation, to the extent required to permit common unitholders to receive their initial unit price plus the minimum quarterly distribution for the quarter during which liquidation occurs plus any unpaid arrearages in payment of the minimum quarterly distribution on the common units. However, there may not be sufficient gain

Index to Financial Statements

upon our liquidation to enable the common unitholders to fully recover all of these amounts, even though there may be cash available for distribution to the holders of subordinated units. Any further net gain recognized upon liquidation will be allocated in a manner that takes into account the incentive distribution rights.

The manner of the adjustment for gain is set forth in the partnership agreement. If our liquidation occurs before the end of the subordination period, we will generally allocate any gain to the partners in the following manner:

If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that clause (3) of the second bullet point above and all of the third bullet point above will no longer be applicable.

We may make special allocations of gain among the partners in a manner to create economic uniformity among the common units into which the subordinated units convert and the common units held by public unitholders.

Index to Financial Statements

If our liquidation occurs before the end of the subordination period, we will generally allocate any loss to our general partner and the unitholders in the following manner:

If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that all of the first bullet point above will no longer be applicable.

We may make special allocations of loss among the partners in a manner to create economic uniformity among the common units into which the subordinated units convert and the common units held by public unitholders.

Our partnership agreement requires that we make adjustments to capital accounts upon the issuance of additional units. In this regard, our partnership agreement specifies that we allocate any unrealized and, for federal income tax purposes, unrecognized gain resulting from the adjustments to the unitholders and the holders of our incentive distribution rights in the same manner as we allocate gain upon liquidation. In the event that we make positive adjustments to the capital accounts upon the issuance of additional units, our partnership agreement requires that we generally allocate any later negative adjustments to the capital accounts resulting from the issuance of additional units or upon our liquidation in a manner that results, to the extent possible, in the partners’ capital account balances equaling the amount that they would have been if no earlier positive adjustments to the capital accounts had been made. In contrast to the allocations of gain, and except as provided above, we generally will allocate any unrealized and unrecognized loss resulting from the adjustments to capital accounts upon the issuance of additional units to the unitholders and the holders of our incentive distribution rights based on their respective percentage ownership of us. In this manner, prior to the end of the subordination period, we generally will allocate any such loss equally with respect to our common and subordinated units. If we make negative adjustments to the capital accounts as a result of such loss, future positive adjustments resulting from the issuance of additional units will be allocated in a manner designed to reverse the prior negative adjustments, and special allocations will be made upon liquidation in a manner that results, to the extent possible, in our unitholders’ capital account balances equaling the amounts they would have been if no earlier adjustments for loss had been made.

Index to Financial Statements

The following table presents selected historical financial data of our Predecessor and selected unaudited pro forma condensed financial data for the Partnership for the periods and as of the dates indicated. The selected 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 selected 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.”

The selected 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:

The unaudited pro forma condensed financial data 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.

Index to Financial Statements

The following discussion and analysis of the financial condition and results of operations for Oasis Midstream Partners LP should be read in conjunction with the audited financial statements and unaudited condensed financial statements of the Predecessor and the unaudited pro forma condensed financial statements of Oasis Midstream Partners LP and the notes thereto included elsewhere in this prospectus. Our Predecessor includes 100% of the operations of OMS, reflecting the historical ownership of these assets by Oasis.

Unless the context otherwise requires, references in this section to “we,” “us,” “our” or like terms, when used in a historical context, refer to our Predecessor and, when used in the present tense or future tense, refer to Oasis Midstream Partners LP and its subsidiaries.

The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. We caution you that assumptions, expectations, projections, intentions or beliefs about future events may, and often do, vary from actual results and the differences can be material. Please read “Cautionary Statement Regarding Forward-Looking Statements.” Also, please read the risk factors and other cautionary statements described under the heading “Risk Factors” included elsewhere in this prospectus. We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law.

We are a growth-oriented, fee-based master limited partnership formed by our sponsor, 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 conduct our business through our ownership of entities that are jointly-owned by Oasis, including a 100%, 10% and 35% equity interest in our DevCos: Bighorn DevCo, Bobcat DevCo and Beartooth DevCo, respectively. 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. We will generate substantially all of our revenues through these contracts, which minimize our direct exposure to commodity prices. Furthermore, we will generally 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 ROFO with respect to its retained 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.

Index to Financial Statements

Our revenues are primarily generated from charging fees for the midstream services we provide, including under the commercial agreements we will enter into or become a party to with OMS and other wholly owned subsidiaries of Oasis in connection with the offering. These services include (i) gas gathering, compression, processing and gas lift services; (ii) crude gathering, stabilization, blending, storage and transportation services; (iii) produced water gathering and disposal services; and (iv) freshwater distribution services. The revenue earned from these services is generally directly related to the volume of natural gas, crude oil and water that flows through our systems. Historically, our Predecessor has provided substantially all of its services to Oasis-operated wells at prevailing market rates. Going forward, we will generate substantially all of our revenues through the contractual arrangements with Oasis described below. By utilizing our infrastructure assets or our planned infrastructure assets, we can provide an array of essential services critical to Oasis’s upstream operations.

Under each of the commercial agreements we will enter into with OMS and other wholly owned subsidiaries of Oasis in connection with the closing of this offering (other than the FERC-regulated crude transportation services agreement), the volumetric fees we charge are automatically increased each calendar year beginning in by %. In addition, beginning on July 1, 2022 and annually thereafter, we may adjust the committed rates under the FERC-regulated crude transportation services agreement by changes in the Oil Pipeline Index. Please read “Certain Relationships and Related Party Transactions—Other Contractual Relationships with Oasis” for additional information about our commercial agreements with OMS and other wholly owned subsidiaries of Oasis.

We have indirect exposure to commodity price risk in that, while our contractual fee structures are not directly tied to commodity prices, persistent low commodity prices may cause Oasis or other customers to delay drilling or shut in production, which would reduce the volumes available for gathering and processing by our infrastructure assets.

Our management intends to use a variety of financial and operating metrics to analyze our operating results and profitability. These metrics are significant factors in assessing our operating results and profitability and include: (i) throughput volumes, (ii) Adjusted EBITDA, (iii) distributable cash flow and (iv) operating and general and administrative expenses.

The amount of revenue we generate primarily depends on the volumes of crude oil, natural gas and water for which we provide midstream services. By connecting new producing wells to our gathering systems and by increasing capacity on our systems, we are able to increase volumes. Additionally, by performing routine maintenance and monitoring of our infrastructure, we are able to minimize service interruptions on our gathering systems.

Under the commercial agreements we will enter into with OMS and other wholly owned subsidiaries of Oasis in connection with the closing of this offering, we will provide (i) gas gathering, compression, processing and gas lift services, with approximately 65,000 dedicated acres and firm capacity for gas attributable to such acreage; (ii) crude gathering, stabilization, blending and storage services, with approximately 65,000 dedicated acres and firm capacity for crude oil attributable to such acreage; (iii) produced water gathering and disposal services, with approximately 65,000 dedicated acres and firm capacity for produced water and flowback water attributable to such acreage; (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 dedicated acres that includes the Hebron, Indian Hills and Red Bank operating areas. In addition, the FERC-regulated crude transportation services agreement we will become a party to has up to

Index to Financial Statements

75,000 barrels per day of operating capacity and firm capacity for committed shippers. Please read “Certain Relationships and Related Party Transactions—Other Contractual Relationships with Oasis” for additional information about our commercial agreements with OMS and other wholly owned subsidiaries of Oasis.

Throughput volumes are affected by changes in the supply of and demand for crude oil and natural gas in the markets served directly or indirectly by our assets. Because the production rate of a well declines over time, we must continually obtain new supplies of crude oil, natural gas and produced water to maintain or increase the throughput volumes on our midstream systems. Because freshwater services are largely dependent on well completion activities, our ability to provide freshwater services is contingent on our customers drilling and completing new wells in and around our freshwater infrastructure. Our customers’, including Oasis’s, willingness to engage in new development activity is determined by a number of factors, the most important of which are the prevailing and projected prices of crude oil and natural gas, the cost to drill, complete and operate a well, expected well performance, the availability and cost of capital and environmental and government regulations. We generally expect the level of development activity to positively correlate with long-term trends in commodity prices and similarly, production levels to positively correlate with development activity.

Our ability to maintain or increase existing throughput volumes and obtain new supplies of crude oil, natural gas and water are impacted by:

We actively monitor producer activity in the areas served by our infrastructure assets to identify opportunities to connect new wells to our gathering systems.

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. We define Adjusted EBITDA attributable to Oasis Midstream Partners LP as Adjusted EBITDA less Adjusted EBITDA attributable to Oasis’s retained interests in our DevCos. Although we have not quantified distributable cash flow on a historical basis, after the closing of this offering, we intend to use distributable cash flow to analyze our liquidity and performance. We define distributable cash flow as Adjusted EBITDA attributable to Oasis Midstream Partners LP less cash paid for interest and estimated maintenance capital expenditures.

Index to Financial Statements

Adjusted EBITDA and distributable cash flow are not presentations made in accordance with GAAP. These non-GAAP supplemental financial measures may be used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies, to assess:

We believe that the presentation of Adjusted EBITDA and distributable cash flow in this prospectus provides useful information to investors in assessing our financial condition and results of operations. The GAAP measures most directly comparable to Adjusted EBITDA and distributable cash flow are net income attributable to Oasis Midstream Partners LP and net cash provided by operating activities, respectively. Adjusted EBITDA and distributable cash flow should not be considered as alternatives to GAAP net income, income from operations, net cash provided by operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Adjusted EBITDA and distributable cash flow have important limitations as analytical tools because they exclude some but not all items that affect net income and net cash provided by operating activities. You should not consider Adjusted EBITDA or distributable cash flow in isolation or as a substitute for analysis of our results as reported under GAAP. Additionally, because Adjusted EBITDA and distributable cash flow may be defined differently by other companies in our industry, our definition of Adjusted EBITDA and distributable cash flow may not be comparable to similarly titled measures of other companies, thereby diminishing their utility.

For a further discussion of the non-GAAP financial measures of Adjusted EBITDA and distributable cash flow and a reconciliation of Adjusted EBITDA and distributable cash flow to their most comparable financial measures calculated and presented in accordance with GAAP, please read “Summary—Non-GAAP Financial Measure” and “Our Cash Distribution Policy and Restrictions on Distributions” included elsewhere in this prospectus.

Our management seeks to maximize the profitability of our operations by effectively managing operating expenses. Operating expenses are primarily comprised of direct labor, utility costs, insurance premiums, third-party service provider costs, related property taxes and other non-income taxes, purchases of freshwater and expenditures to repair, refurbish and replace facilities and to maintain equipment reliability, integrity and safety.

Operating expenses fluctuate from period to period depending on the mix of activities performed during any specified period and the timing of these expenses. Because many of these expenses are fixed in nature, we expect to lower operating expenses as a percentage of revenue as we add incremental volumes onto our gathering systems. We will seek to manage our operating expenditures by scheduling periodic maintenance on our assets in order to minimize significant variability in these expenditures and their impact on our cash flow.

Historically, our Predecessor’s general and administrative expense included an allocation of charges for the management and operation of our assets by Oasis for general and administrative services, such as information technology, treasury, accounting, human resources and legal services and other financial and administrative

Index to Financial Statements

services. Following the completion of this offering, Oasis will charge us a combination of direct and allocated charges for general and administrative services.

We anticipate incurring approximately $2.5 million of incremental general and administrative expenses attributable to being a publicly traded partnership. These incremental general and administrative expenses, and the variable component of the general and administrative costs that we anticipate incurring under the operational services and secondment agreement and the omnibus agreement, are not reflected in our historical or our pro forma condensed financial statements. Our future general and administrative expense will also include compensation expense associated with the Oasis Midstream Partners LP 2017 Long-Term Incentive Plan.

Items Affecting Comparability of Our Financial Condition and Results of Operations

Our future results of operations may not be comparable to our Predecessor’s historical results of operations for the following reasons:

Revenues. In connection with the closing of this offering, we will enter into 15-year contracts for natural gas services (gathering, compression, processing and gas lift), crude oil services (gathering, stabilization, blending and storage), produced water services (gathering and disposal) and freshwater services (fracwater and flushwater distribution) with OMS and certain other wholly owned subsidiaries of Oasis. 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, our Predecessor had provided substantially all of their services to Oasis-operated wells at prevailing market rates. Following the closing of this offering, we will earn revenues under our long-term, fixed-fee commercial agreements with Oasis.

Oasis’s Retained Interests. Our Predecessor’s results of operations included 100% of the revenues and expenses associated with OMS. At the closing of this offering, Oasis will contribute to us a 100%, 10% and 35% equity interest in Bighorn DevCo, Bobcat DevCo and Beartooth DevCo, respectively. Following the closing of this offering, we will consolidate the financial position and results of operations of our equity interests and Oasis’s retained interests. Oasis’s retained portions of these interests will be reflected as non-controlling interests in our financial statements. Accordingly, our financial statements will be adjusted to reflect Oasis’s continued ownership of a non-controlling 90% and 65% equity interest in Bobcat DevCo and Beartooth DevCo, respectively.

Excluded Assets. Certain midstream infrastructure assets, liabilities, revenues and expenses included in our Predecessor’s historical financial statements will be excluded from the businesses of the DevCos upon formation.

General and Administrative Expenses. Our Predecessor’s general and administrative expenses included direct labor and indirect shared service expense allocations for support functions provided by Oasis, as Oasis provided substantial labor and overhead support for us. These support functions included general and administrative services, such as legal, corporate recordkeeping, planning, budgeting, regulatory, accounting, billing, business development, treasury, insurance administration and claims processing, risk management, health, safety and environmental, information technology, human resources, investor relations, cash management and banking, payroll, internal audit, taxes and engineering. Allocations were based primarily on headcount and direct usage during the respective periods of operations. We believe that these allocations were reasonable and reflected the utilization of services provided and benefits received, but may have differed from the cost that would have been incurred had we operated as a stand-alone company for the years presented. For more information about such fees and services, please read “Certain Relationships and Related Party Transactions—Agreements with Affiliates in Connection with the Transactions—Services and Secondment Agreement.”

Index to Financial Statements

Following the closing of this offering, under our services and secondment agreement, Oasis will continue to charge us a combination of direct and indirect allocated charges for general and administrative services. We also currently anticipate incurring approximately $2.5 million of incremental general and administrative expenses attributable to operating as a publicly traded partnership.

Financing. Historically, our Predecessor’s operations and capital expenditure requirements were financed solely with capital contributions from Oasis. Our Predecessor recognized interest expense related to its funding activity with Oasis based on capital expenditures for the period using the weighted average effective interest rate of Oasis’s long-term indebtedness. For the years ended December 31, 2016 and 2015, interest expense, net of capitalized interest, allocated to our Predecessor was $5.5 million and $4.5 million, respectively. For the three months ended March 31, 2017 and 2016, interest expense, net of capitalized interest, allocated to the Predecessor was $1.2 million and $0.5 million, respectively. Capitalized interest costs totaled $4.4 million and $2.9 million for the years ended December 31, 2016 and 2015, respectively, and $0.1 million and $1.2 million for the three months ended March 31, 2017 and 2016, respectively.

In connection with the closing of this offering, we intend to have no debt and an available borrowing capacity of $ million under a new revolving credit facility which we may use to fund working capital, acquisitions, distributions and capital expenditures and for other general partnership purposes. As a result, we will incur interest expense on any borrowings, pay a commitment fee for the unutilized portion of the revolving credit facility and amortize the debt issuance costs incurred in connection with the revolving credit facility over the term of the revolving credit facility. Following the closing of this offering, we will also have separate bank accounts, and, based on the terms of our cash distribution policy, we expect that we will distribute most of the cash generated by our operations to our unitholders. As a result, we expect to fund future expansion capital expenditures and acquisitions primarily from a combination of borrowings under our new revolving credit facility and the issuance of additional equity or debt securities.

Income Taxes. Our Predecessor determined income tax expense and related deferred tax balance sheet accounts on a separate return method for the years ended December 31, 2016 and 2015 and for the three months ended March 31, 2017 and 2016. Following the completion of this offering, we expect to be treated as a partnership for U.S. federal income tax purposes and, therefore, generally will not be liable for entity-level federal income taxes.

We plan to pursue strategic acquisitions that complement our existing midstream infrastructure and that will provide attractive returns for our unitholders. We anticipate that, pursuant to our ROFO with Oasis, we will have the opportunity to make accretive acquisitions from Oasis by acquiring additional equity interests in our DevCos, as well as acquiring assets that Oasis builds on its current acreage that it elects to sell in the future. Following this offering, Oasis will retain a non-controlling 90% and 65% equity interest in Bobcat DevCo and Beartooth DevCo, respectively. Please read “Certain Relationships and Related Party Transactions—Agreements with Affiliates in Connection with the Transactions—Omnibus Agreement.”

Historically, substantially all of the throughput volumes on our midstream assets were produced from Oasis-operated oil and natural gas wells. We are actively marketing our natural gas, crude oil, produced water gathering and disposal services and freshwater distribution services to, and pursuing strategic relationships with, third-party producers in order to attract additional volumes and/or expansion opportunities. 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.

Index to Financial Statements

After the closing of this offering, we will generate substantially all of our revenues under fee-based agreements with Oasis. We expect these contracts will promote cash flow stability and minimize our direct exposure to commodity price fluctuations. However, commodity price fluctuations indirectly influence our activities and results of operations over the long term because they may affect production rates and investments by Oasis and third parties in the development of oil and natural gas reserves. Generally, development activity will increase as oil and natural gas prices increase. Our assets’ throughput volumes depend primarily on the volumes of oil and natural gas produced by Oasis in the Williston Basin, which, in turn, is ultimately dependent on the margins Oasis realizes for its exploration and production activities. These margins for Oasis depend on the price of oil and natural gas. These prices are volatile and influenced by numerous factors beyond our or Oasis’s control, including the domestic and global supply of and demand for oil and natural gas. The commodities trading markets, as well as other supply and demand factors, may also influence the selling prices of oil and natural gas.

Total midstream revenues were $37.6 million for the three months ended March 31, 2017, which was a 26% increase year over year. This increase was driven by a $12.1 million increase related to higher natural gas volumes gathered and processed coupled with a $4.3 million increase related to higher oil volumes gathered, stabilized and transported as a result of the start up of our natural gas processing plant and our oil gathering system in the second half of 2016, respectively. These increases were offset by a decrease of $5.0 million and $3.7 million related to lower saltwater disposal and freshwater sales, respectively.

Total revenues were $120.9 million for the year ended December 31, 2016, which was a 15% increase year over year. This increase was driven by a $11.7 million increase related to increased water volumes flowing through our SWD systems as a result of new well connections and capacity additions, coupled with a $10.2 million increase related to natural gas volumes gathered and processed with the startup of our natural gas processing plant in the third quarter of 2016 and a $2.7 million increase related to crude oil volumes gathered, stabilized and transported beginning in the fourth quarter of 2016, offset by an $8.3 million decrease in freshwater sales primarily due to decreased Oasis completion activity in response to the low commodity-price environment.

Index to Financial Statements

The following table summarizes our operating expenses and other income and expenses for the periods presented:

Direct operating expenses. The $1.7 million increase for the three months ended March 31, 2017 as compared to the three months ended March 31, 2016 was primarily related to the start up of our natural gas processing plant, oil gathering system and additional infrastructure during 2016, partially offset by a decrease in freshwater purchases.

Depreciation and amortization. Depreciation and amortization expense increased $1.8 million to $3.5 million for the three months ended March 31, 2017 as compared to 2016, primarily as a result of additional assets placed into service, including our natural gas processing plant in the third quarter of 2016.

General and administrative (“G&A”) expenses. G&A expenses include direct labor and allocated costs of overhead support provided by Oasis, such as legal, corporate recordkeeping, planning, budgeting, regulatory, accounting, billing, business development, treasury, insurance administration and claims processing, risk management, health, safety and environmental, information technology, human resources, investor relations, cash management and banking, payroll, internal audit, taxes and engineering. The increase of $1.2 million in our G&A expenses for the three months ended March 31, 2017 as compared to 2016 was primarily a result of increased employee compensation as a result of organizational growth due to the start up of our natural gas processing plant in the third quarter of 2016.

Interest expense. We recognized interest expense related to our funding activity with Oasis based on capital expenditures for the period using the weighted average effective interest rate for Oasis’s long-term indebtedness. Our allocated interest expense, net of capitalized interest, increased $0.7 million for the three months ended March 31, 2017 as compared to 2016, primarily related to lower capitalized interest during the three months ended March 31, 2017 due to lower work in progress as a result of the completion of our natural gas processing plant in the third quarter of 2016. Capitalized interest costs totaled $0.1 million and $1.2 million for the three months ended March 31, 2017 and 2016, respectively.

Index to Financial Statements

Direct operating expenses. The $0.7 million increase for the year ended December 31, 2016 as compared to the year ended December 31, 2015 was primarily related to the startup of our natural gas processing plant and integrated crude system in late 2016, coupled with an increase in water trucking expenses due to produced water from Oasis’s operated wells temporarily exceeding salt water disposal capacity in certain areas and at certain times, offset by a decrease in freshwater purchases for the year ended December 31, 2016 as compared to the year ended December 31, 2015.

Depreciation and amortization. Depreciation and amortization expense increased $2.8 million to $8.5 million for the year ended December 31, 2016 as compared to the year ended December 31, 2015, primarily as a result of additional assets being placed into service, including our natural gas processing plant in the third quarter of 2016.

Impairment. We recorded an impairment charge of $2.1 million during the year ended December 31, 2015 to adjust the carrying value of our properties held for sale to their estimated fair value, determined based on the expected sales price, less costs to sell. No impairment charges were recorded for the year ended December 31, 2016.

G&A expenses. G&A expenses include direct labor and allocated costs of overhead support provided by Oasis, such as legal, corporate recordkeeping, planning, budgeting, regulatory, accounting, billing, business development, treasury, insurance administration and claims processing, risk management, health, safety and environmental, information technology, human resources, investor relations, cash management and banking, payroll, internal audit, taxes and engineering. The increase of $1.9 million in our G&A expenses for the year ended December 31, 2016 as compared to the year ended December 31, 2015 was primarily a result of increased employee compensation expense due to our organizational growth primarily due to the startup of our natural gas processing plant in the third quarter of 2016.

Interest expense. We recognized interest expense related to our funding activity with Oasis based on capital expenditures for the period using the weighted average effective interest rate for Oasis’s long-term indebtedness. Our allocated interest expense, net of capitalized interest, increased $1.0 million due to an increase in capital expenditures, partially offset by an increase in capitalized interest for the year ended December 31, 2016 as compared to 2015. Capitalized interest costs totaled $4.4 million and $2.9 million for the years ended December 31, 2016 and 2015, respectively.

Historically, our Predecessor’s primary sources of liquidity included cash generated from operations and capital contributions from our sponsor, Oasis. We currently participate in Oasis’s centralized cash management system. Therefore, our Predecessor’s cash receipts are deposited in Oasis’s bank accounts, all cash disbursements are made from those accounts, and our Predecessor maintains no bank accounts dedicated solely to our current assets. Thus, our Predecessor’s financial statements reflect a zero cash balance for the year ended December 31, 2016 and 2015 and for the three months ended March 31, 2017 and 2016. Our Predecessor’s primary use of capital has been for the development of midstream infrastructure.

In connection with this offering, we will establish separate bank accounts, but Oasis will continue to provide treasury services on our behalf under our services and secondment agreement. We expect our ongoing sources of liquidity following this offering to include cash generated from operations, borrowings under our new revolving credit facility and, if necessary, the issuance of additional equity or debt securities. We believe that cash generated from these sources will be sufficient to meet our short-term working capital needs, long-term capital expenditure requirements and quarterly cash distributions. In connection with the closing of this offering, we intend to have no debt and full borrowing capacity under the new -year, $ million revolving credit facility.

Index to Financial Statements

Based on the terms of our cash distribution policy, we expect that we will distribute most of the cash generated by our operations to our unitholders. As a result, we expect to fund future expansion capital expenditures and acquisitions primarily from a combination of borrowings under our revolving credit facility and the issuance of additional equity or debt securities. We expect our future cash requirements relating to working capital, maintenance capital expenditures and quarterly cash distributions to our unitholders will be funded from cash flows internally generated from our operations.

The board of directors of our general partner will adopt a cash distribution policy pursuant to which we intend to distribute a minimum quarterly distribution of $ per unit per quarter ($ per unit on an annualized basis), which equates to an aggregate distribution of approximately $ million per quarter, or approximately $ million per year, based on the number of common units and subordinated units to be outstanding immediately after completion of this offering. 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. We do not have a legal or contractual obligation to pay distributions quarterly or on any other basis at our minimum quarterly distribution rate or at any other rate. Please read “Our Cash Distribution Policy and Restrictions on Distributions.”

Upon the closing of this offering, we will enter into a new $ million secured revolving credit facility with , as administrative agent, and a syndicate of lenders, which will mature on the anniversary of the closing date of this offering. Our new revolving credit facility will be available for working capital, capital expenditures, permitted acquisitions and general corporate purposes, including distributions. In addition, we expect that our new revolving credit facility will include a sublimit of up to $ million for letters of credit and a sublimit of up to $ million for swing line loans. Substantially all of our assets, but excluding equity in and assets of certain joint ventures and unrestricted subsidiaries and other customary exclusions, will be pledged as collateral under our new revolving credit facility.

We expect that our new revolving credit facility will contain various covenants and restrictive provisions that will limit our ability (as well as the ability of our subsidiaries) to, among other things:

In addition, we expect that our new revolving credit facility will restrict our ability to make distributions on, or redeem or repurchase, our equity interests, except for distributions of available cash so long as, both at the time of the distribution and after giving effect to the distribution, no default exists under the new revolving credit facility. Our new revolving credit facility will also require us to maintain certain financial covenants.

We also expect that our new revolving credit facility will contain events of default customary for facilities of this nature, including, but not limited, to:

Index to Financial Statements

Upon the occurrence and during the continuation of an event of default, subject to the terms and conditions of our new revolving credit facility, we expect that the lenders will be able to declare any outstanding principal balance of our credit facility, together with accrued and unpaid interest, to be immediately due and payable and exercise other remedies.

The following table and discussion presents a summary of our Predecessor’s cash flows for the three months ended March 31, 2017 and 2016 and for the years ended December 31, 2016 and 2015:

Net cash provided by operating activities was $20.4 million and $19.5 million for the three months ended March 31, 2017 and 2016, respectively. The increase in cash flows provided by operating activities for the three months ended March 31, 2017 as compared to 2016 was primarily due to higher natural gas volumes gathered and processed and higher oil volumes gathered, stabilized and transported as a result of the start up of our natural gas processing plant and our oil gathering system, respectively, in the second half of 2016.

Net cash provided by operating activities was $72.1 million and $54.1 million for the year ended December 31, 2016 and 2015, respectively. The increase in cash flows provided by operating activities or the year ended 2016 as compared to 2015 was primarily due to increases in produced water transport and disposal and natural gas gathering and processing associated with the startup of the natural gas processing plant in the third quarter of 2016.

Our Predecessor’s historical capital expenditures were funded by Oasis through capital contributions.

Net cash used in investing activities was $23.8 million and $27.4 million for the three months ended March 31, 2017 and 2016, respectively. The decrease in net cash used in investing activities for the three months ended March 31, 2017 as compared to 2016 was attributable to an increase in capital expenditures in 2016 primarily due to the development of the natural gas processing plant and additional infrastructure that were placed into service during 2016.

Net cash used in investing activities was $157.9 million and $120.2 million for the year ended December 31, 2016 and 2015, respectively. The increase in net cash used in investing activities for the year ended December 31, 2016 as compared to the year ended December 31, 2015 was attributable to an increase in capital expenditures primarily due to the development of the natural gas processing plant, integrated crude system and additional pipelines.

Index to Financial Statements

Our Predecessor’s historical financing activities were the result of capital contributions from Oasis. As noted above, our Predecessor’s operations were financed as part of Oasis’s integrated operations and our Predecessor recognized interest expense related to its funding activity with Oasis based on capital expenditures for the period using the weighted average effective interest rate for Oasis’s long-term indebtedness. Following the closing of this offering, we will have separate bank accounts and a new revolving credit facility, as described above.

For the three months ended March 31, 2017 and 2016, net cash provided by financing activities were $3.4 million and $8.0 million, respectively, as a result of capital contributions from Oasis. For the year ended December 31, 2016 and 2015, net cash provided by financing activities were $85.8 million and $66.1 million, respectively, as a result of capital contributions from Oasis.

Subsequent to the completion of this offering, we will fund 100%, 10% and 35% of the capital expenditures related to Bighorn DevCo, Bobcat DevCo and Beartooth DevCo, respectively. We estimate that total capital expenditures attributable to our DevCos for the twelve months ending , 2017 will be $ million ($ million net to our ownership interests in our DevCos). We estimate that expansion capital expenditures for the twelve months ending , 2017 will be $ million ($ million net to our ownership interests in our DevCos), primarily relating to gathering pipeline expansions, new well pad connections and expansion or construction of additional centralized gathering facilities. We estimate that maintenance capital expenditures will be $ million ($ million net to our ownership interests in our DevCos) for the twelve months ending , 2017. Please read “Our Cash Distribution Policy and Restrictions on Distributions—Significant Forecast Assumptions—Capital Expenditures.”

Index to Financial Statements

We anticipate that we will continue to make significant expansion capital expenditures in the future. Consequently, our ability to develop and maintain sources of funds to meet our capital requirements is critical to our ability to meet our growth objectives. We expect that our future expansion capital expenditures will be funded by borrowings under our new revolving credit facility and the issuance of debt and equity securities.

We have the following contractual obligations and commitments as of December 31, 2016:

The discussion and analysis of our Predecessor’s financial condition and results of operations are based upon our Predecessor’s audited financial statements and unaudited condensed financial statements, which have been prepared in accordance with GAAP and are included elsewhere in this prospectus. The preparation of our financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is a reasonable likelihood that materially different amounts could have been reported under different conditions or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our financial statements. We provide expanded discussion of our more significant accounting policies, estimates and judgments used in preparation of our financial statements below. See Note 2 to both our audited financial statements and unaudited condensed financial statements for a discussion of additional accounting policies and estimates made by management.

Our Predecessor evaluates the ability to recover the carrying amount of long-lived assets and determines whether such long-lived assets have been impaired. Impairment exists when the carrying amount of an asset exceeds estimates of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. Our Predecessor’s impairment analyses require management to apply judgment in identifying impairment indicators and estimating future cash flows. When alternative courses of action to recover the carrying amount of a long-lived asset are under consideration, estimates of future undiscounted cash flows take into account possible outcomes and probabilities of their occurrence. If the carrying amount of the long-lived asset is not recoverable

Index to Financial Statements

based on the estimated future undiscounted cash flows, the impairment loss is measured as the excess of the asset’s carrying amount over its estimated fair value, such that the asset’s carrying amount is adjusted to its estimated fair value with an offsetting charge to impairment expense.

Fair value represents the estimated price between market participants to sell an asset in the principal or most advantageous market for the asset, based on assumptions a market participant would make. When warranted, management assesses the fair value of long-lived assets using commonly accepted techniques and may use more than one source in making such assessments. The factors used to determine fair value are subject to management’s judgment and expertise and include, but are not limited to, recent third-party comparable sales, internally developed discounted cash flow analyses and analyses from outside advisors. Significant changes, such as changes in contract rates or terms, the condition of an asset or management’s intent to utilize the asset, generally require management to reassess the cash flows related to long-lived assets. A reduction of the carrying value of fixed assets would represent a Level 3 fair value measurement.

If actual results are not consistent with our assumptions and estimates or our assumptions and estimates change due to new information, we may be exposed to additional impairment charges. Ultimately, a prolonged period of lower commodity prices may adversely affect our estimate of future operating results through lower throughput volumes on our assets, which could result in future impairment charges due to the potential impact on our operations and cash flows.

We record the fair value of a liability for a legal obligation to retire an asset in the period in which the liability is incurred, with the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. For SWD wells, this is the period in which the well is drilled or acquired. The ARO represents the estimated amount we will incur to plug, abandon and remediate the SWD properties at the end of their useful lives, in accordance with applicable state laws. The liability is accreted to its present value each period and the capitalized costs are depreciated using the straight-line method. The accretion expense is recorded as a component of depreciation and amortization in our Statements of Operations.

Some of our assets, including certain pipelines and the natural gas processing plant, have contractual or regulatory obligations to perform remediation and, in some instances, dismantlement and removal activities when the assets are abandoned. We are not able to reasonably estimate the fair value of the ARO for these assets because the settlement dates are indeterminable given the expected continued use of the assets with proper maintenance. We will record an ARO for these assets in the periods in which the settlement dates become reasonably determinable.

We determine the ARO by calculating the present value of estimated cash flows related to the liability. Estimating the future ARO requires management to make estimates and judgments regarding timing and existence of a liability, as well as what constitutes adequate restoration. Inherent in the fair value calculation are numerous assumptions and judgments including the ultimate costs, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the related asset.

Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the years ended December 31, 2016 and 2015. Although the impact of inflation has been insignificant in recent years, it is still a factor in the United States economy, and in the past, we have tended to experience inflationary pressure on the cost of oilfield services and equipment as increasing oil and natural gas prices increased development activity in our areas of operations.

Index to Financial Statements

Currently, we do not have any off-balance sheet arrangements as defined by the SEC. In the ordinary course of business, we enter into various commitment agreements and other contractual obligations, some of which are not recognized in our financial statements in accordance with GAAP. See “—Cash Flows—Obligations and Commitments” above as well as Note 11 to our audited financial statements for the years ended December 31, 2016 and 2015 and Note 10 to our unaudited condensed financial statements for the three months ended March 31, 2017 and 2016, included elsewhere in this prospectus for a description of our commitments and contingencies.

Demand for crude oil and natural gas generally decreases during the spring and fall months and increases during the summer and winter months. However, seasonal anomalies such as mild winters or mild summers sometimes lessen this fluctuation. In addition, certain crude oil and natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer. This can also lessen seasonal demand fluctuations. In respect of our completed midstream systems, we do not expect seasonal conditions to have a material impact on our throughput volumes. Severe or prolonged winters may, however, impact our ability to complete additional well connections or construction projects, which may impact the rate of our growth. In addition, severe weather may also impact or slow the ability of Oasis to execute its drilling and development plan and increase operating expenses associated with repairs or anti-freezing operations.

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risk. The term “market risk” refers to the risk of loss arising from adverse changes in commodity prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures.

Commodity Price Risk. We have limited direct exposure to risks associated with fluctuating commodity prices due to the nature of our business and our long-term, fixed-fee arrangements with Oasis. However, to the extent that our future contractual arrangements with Oasis or third parties do not provide for fixed-fee structures, we may become subject to commodity price risk. Additionally, as substantially all of our revenues are derived from Oasis, we will be indirectly subject to risks associated with fluctuating commodity prices to the extent that lower commodity prices adversely affect Oasis’s production, drilling schedule, financial condition, leverage, market reputation, liquidity, results of operations or cash flows.

Interest Rate Risk. As described above, in connection with the closing of this offering, we intend to enter into a new $ million revolving credit facility. We may, in the future, utilize interest rate derivatives to mitigate interest rate exposure in efforts to reduce interest rate expense related to debt issued under our revolving credit facility. Interest rate derivatives would be used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio.

Index to Financial Statements

We obtained the information in this prospectus about the natural gas, crude and water industries from several independent outside sources, include: the Energy Information Administration, an independent statistical and analytical agency within the U.S. Department of Energy, which we refer to as EIA, the North Dakota Industrial Commission, which we refer to as the NDIC, and the U.S. Geological Survey, which we refer to as USGS.

Our assets consist of a diversified portfolio of midstream infrastructure assets in North America, with a current focus in the Williston Basin. Our midstream infrastructure assets primarily focus on natural gas gathering, compression, processing and gas lift supply; crude gathering, terminaling and transportation; gathering, transportation and disposal of produced water; and freshwater distribution. The market in which we operate, which serves customers from the point of production and extends through the gathering, processing and treating of hydrocarbons until delivering them to takeaway pipelines, is customarily referred to as the “midstream” market.

The midstream energy industry encompasses a broad array of services and provides the link between the exploration and production of oil and natural gas and the delivery of that oil and natural gas and its by-products to industrial, commercial and residential users. Some of the principal components of the industry include the gathering, processing, fractionation and transporting of natural gas and NGLs, the gathering and transporting, storage and blending of crude oil, the gathering, transporting and disposal of produced water produced during the drilling and completion stages of the production process and the delivery of freshwater for use during hydraulic fracturing and production optimization.

The services provided by midstream energy companies are generally classified into the categories described below. As indicated above, we do not currently provide all of these services, although we may provide other midstream infrastructure services in the future. In connection with future acquisitions from Oasis or other third-parties, we may acquire additional midstream assets in other portions of the midstream value chain or strengthen our current midstream infrastructure services offered.

The natural gas midstream industry provides the link between the exploration and production of natural gas from the wellhead and the delivery of natural gas and its by-products to industrial, commercial and residential end-users. Companies generate revenues at various links within the midstream value chain by gathering, compression, processing, treating, fractionating, transporting, storing or marketing natural gas and NGLs. Our natural gas midstream operations currently focus on the gathering, compression and processing of natural gas

Index to Financial Statements

along with providing gas lift supply for artificial lift. The following diagram illustrates the various components of the natural gas midstream value chain and the services that are specifically offered by us:

The services we provide are generally classified into the categories described below.

Gathering. At the initial stages of the midstream value chain, a network of typically small diameter pipelines known as gathering systems directly connect to wellheads, pad sites or other receipt points in the production area. These gathering systems transport natural gas from the wellhead and other receipt points either to compressor stations, treating and processing plants (if the natural gas is wet) or directly to intrastate or interstate pipelines (if the natural gas is dry).

Gathering systems are typically designed to be highly flexible to provide different levels of service (such as higher or lower pressure) and scalable to allow for additional production and well connections without significant incremental capital expenditures. Gathering systems are operated at pressures that both meet the contractual service requirements and maximize the total throughput from all connected wells. Competition in the natural gas gathering industry is typically regional and based on proximity to natural gas producers, as well as access to viable treating and processing plants or intrastate and interstate pipelines. Overall demand for gathering services in a particular area is generally driven by natural gas producer activity in the area.

Compression. Gathering systems are operated at design pressures that enable the maximum amount of production to be gathered from connected wells. Through a mechanical process known as compression, volumes of natural gas at a given pressure are compressed to a sufficiently higher pressure, thereby allowing those volumes to be delivered into a higher pressure downstream pipeline to be brought to market. Since wells produce at progressively lower field pressures as they age, it becomes necessary to add additional compression over time near the wellhead to maintain throughput across the gathering system.

Index to Financial Statements

Processing. The principal components of natural gas are methane and ethane, but natural gas often contains varying amounts of other NGLs, which are heavier hydrocarbons that are found in some natural gas streams. Even after treating and dehydration, some natural gas is not suitable for long-haul intrastate and interstate pipeline transportation or commercial use because it contains NGLs, which increase BTU levels beyond transport specifications. This natural gas, referred to as liquids-rich natural gas, must be processed to remove these heavier hydrocarbon components. However, NGLs are also valuable commodities once removed from the natural gas stream and are utilized in the refining and petrochemical industries. The removal and separation of NGLs usually takes place in a processing plant using industrial processes that exploit differences in the weights, boiling points, vapor pressures and other physical characteristics of NGL components. Once the NGL stream has been separated from the natural gas stream, and separated into products through fractionation, the resulting NGL products are then transported by pipe, rail or truck to downstream NGL terminal, storage and distribution networks or also transported directly to end users.

Gas Lift. Gas lift is a method of artificial lift that uses an external source of high-pressure gas for supplementing formation gas to lift the well fluids. The principle of gas lift is that gas injected into the tubing reduces the density of the fluids in the tubing, and the bubbles have a “scrubbing” action on the liquids. Both factors act to lower the flowing bottomhole pressure at the bottom of the tubing.

The following chart shows natural gas production from the Bakken formation since January 2010:

The crude oil midstream industry provides the link between the exploration and production of crude oil from the wellhead and the delivery of crude oil to storage facilities, crude oil pipelines and refineries. Companies generate revenues at various links within the midstream value chain by gathering, treating, transporting, storing or marketing crude oil. Our crude oil midstream operations currently focus on the gathering, stabilization,

Index to Financial Statements

blending, storage and transportation of crude oil. The following diagram illustrates the various components of the crude oil midstream value chain and the services that are specifically offered by us:

The services we provide are generally classified into the categories described below.

Gathering. Crude oil gathering assets provide the link between crude oil production gathered at the well site or nearby collection points and crude oil terminals, storage facilities, long-haul crude oil pipelines and refineries. Crude oil gathering assets generally consist of a network of small-diameter pipelines that are connected directly to the well site or central receipt points delivering into large-diameter trunk lines. Pipeline transportation is generally the lowest cost option for transporting crude oil. Competition in the crude oil gathering industry is typically regional and based on proximity to crude oil producers, as well as access to viable delivery points. Overall demand for gathering services in a particular area is generally driven by crude oil producer activity in the area. To the extent there are not enough volumes to justify construction of or connection to a pipeline system, trucking crude oil from a well site to nearby collection points can also be a competitor to crude oil gathering pipeline systems, but is typically not the lowest cost nor the most reliable option for transporting crude oil from a producer’s perspective.

Stabilization and Blending. The process of crude stabilization lowers the concentration of light gases, or NGLs, absorbed in the crude oil when it is produced. Crude stabilization reduces vapor pressure, making the crude oil less volatile to meet standards and regulations for storage and shipment via pipeline or rail tank cars. Crude stabilization may also be designed to remove corrosive elements such as hydrogen sulfide, which can damage storage vessels, pipelines and tank cars. Blending is a process used to achieve specified grades of crude oil to meet specification provided by pipelines, rail cars, barges and trucks that receive and redeliver crude oil.

Index to Financial Statements

Storage/Terminaling. Terminaling and storage facilities and related short-haul pipelines complement crude oil transportation systems, refinery operations and refined products transportation and play a key role in moving refined products to the end-use market. Crude oil terminals are generally used for distribution, storage, inventory management and blending.

Crude Oil Transportation. Pipeline transportation is generally the lowest cost method for shipping crude oil and transports about two-thirds of the petroleum shipped in the United States. Crude oil pipelines transport oil from the wellhead to logistics hubs and/or refineries. Common carrier pipelines have published tariffs that are regulated by the FERC or state authorities. Pipelines not engaged in the interstate transportation of crude may also be proprietary or leased entirely to a single customer. Logistic hubs like Cushing, Oklahoma provide storage and connections to other pipeline systems and modes of transportation, such as railroads and trucks. Overall demand for gathering services in a particular area is generally driven by crude oil producer activity in the area.

The following chart shows crude oil production from the Bakken formation since January 2010:

Fluids management and production by-product management is a critical process in the oil and natural gas production cycle as several by-products are typically generated during drilling and completion of, and production from, oil and natural gas wells. Produced water is the largest volume by-product associated with oil and natural gas exploration and production. Per North Dakota Department of Mineral Resources, approximately 452 million barrels of produced water were generated in 2016 in North Dakota from over 11,000 producing wells on average throughout the year. This is forecasted to grow in the key U.S. lower-48 production basins, including the Williston Basin, driven by the development of unconventional resource plays. Continued growth of produced water volumes is tied to the constant increase of new wells coming online and changes to hydraulic fracturing techniques.

The SWD process typically involves transportation, processing and disposal facilities, including the process of disposing of produced water in SWD wells. We are directly engaged in the gathering, transportation and disposal of produced water in SWD wells.

Index to Financial Statements

Freshwater, when used in the hydraulic fracturing process, is integral to the completion of wells for production. Hydraulic fracturing is a well stimulation process that utilizes large volumes of freshwater and sand (or another proppant) combined with fracturing chemical additives that are pumped at high pressure to crack open previously impenetrable rock and release hydrocarbons. Freshwater refers to water that has been treated and also to water that has been withdrawn from a river or ground water. Although some larger producers have (or have begun construction of) freshwater systems, many other producers still rely on third-party providers for distribution services. Providers range from independent, dedicated trucking providers to consolidated service companies that provide a full range of oilfield services, including freshwater distribution. Freshwater distribution also includes the supply of freshwater used during production operations to flush out existing wells in order to prevent downhole scaling.

The following diagram illustrates the various components of freshwater distribution, produced water gathering, transportation and disposal and the services that are specifically offered by us:

The services we provide are generally classified into the categories described below.

Produced Water. Oil and natural gas operations produce two primary types of produced water by-products:

Produced Water from the Reservoir. Produced water is water that naturally occurs in the formation that returns up to the surface over the life of a producing oil or natural gas well. Produced water must be continually separated from a well’s valuable oil and natural gas production and hauled away via truck or pipeline for a well to stay in production. Produced water is the largest by-product by volume associated with oil and natural gas production and can comprise of over 20% of the volume of total liquids produced from a well over time and over 95% of the total oilfield by-product by volume.

Flowback. In the drilling and completion stages of oil and natural gas production, large volumes of water and other types of fluids are required. Hydraulic fracturing is a key component of the completion stage of an oil and natural gas well that requires large quantities of water. After the water is pumped into the well, it returns to the surface over time. Ten to fifty percent of the water returns as “flowback” during the first several weeks following the fracturing process, and a large percentage of the remainder, as well as pre-existing water in the formation, returns to the surface as produced water over the life of the well.

Transportation of Produced Water. The produced water disposal process involves transporting produced water from an oil or natural gas well to a disposal site. The produced water is typically transported by either pipelines or trucks.

Pipelines. Pipelines, also called gathering systems, are a method for transporting produced water from the well location to the SWD facility. The initial capital costs to build the infrastructure for piping produced water are greater than the capital costs of transporting the produced water by truck, but the operating expenses after the pipeline is constructed can be significantly lower. Additionally, the net economics of transporting produced water by pipeline over the lifespan of an oil or natural gas well can be substantially superior, especially for long-lived wells.

Index to Financial Statements

Trucking. Trucking is the most common method of transporting produced water in the industry due to capital requirements and construction timelines for developing pipeline infrastructure. Trucking has the advantages of lower capital costs for the producer compared to pipelines and the ability to easily access multiple SWD facilities. However, operating expenses associated with trucking (such as labor and fuel costs), business interruption, costs of complying with various local regulations, insurance and costs related to road repairs and accidents can be significant. In addition, the service reliability of trucking is generally lower because uncontrollable events, such as weather and road repairs, may limit the ability of trucks to drive to the wellsite to gather production.

SWD Facilities/SWD Wells. The primary methods for handling produced water and flowback include U.S. EPA Class II SWD wells, where produced water and flowback are treated and injected subsurface; evaporation pits, where the water is evaporated at the surface; and recycling facilities, where produced water and flowback are treated in a manner that allows some portion of the water to be recycled for future fracturing processes or other beneficial uses.

In all cases, the produced water and flowback must be processed and disposed of in a manner consistent with applicable environmental regulations. The manner in which the disposal process is performed is dictated in part by local regulations that can vary from region to region or state to state. As a result of these regulatory requirements and the level of expertise required to properly process and dispose of produced water, producers are requiring increased compliance expertise and operational experience from their service providers.

Transportation of Freshwater. There are two primary methods of transporting freshwater from a source to a well location:

Pipelines. The initial capital costs to build pipeline infrastructure for freshwater distribution systems are significantly greater than the capital costs of transporting freshwater by truck, but the operating expenses for operators after pipelines are constructed are typically significantly lower. Following construction, the most significant ongoing costs of a pipeline system are personnel and pumping costs. Because Oasis’s acreage is located in large blocks in the core areas of the Williston Basin, we are able to use our pipeline systems to efficiently distribute freshwater for certain of Oasis’s well completions.

Trucking. Trucking has the advantage of lower up-front capital costs for the producer compared to pipelines. However, operating expenses associated with trucking (such as labor and fuel costs), costs of complying with various local regulations, insurance and costs related to road repairs and accidents can be significant. We currently do not plan to distribute freshwater via trucking to Oasis or any other producer.

Index to Financial Statements

The following chart shows produced water production from the Bakken formation since January 2010:

We believe that producers’ demand for natural gas gathering and processing, crude oil gathering and produced water gathering and disposal services will persist in both high and low-commodity price environments. As production in the Williston Basin rises, the amount of natural gas, crude oil and produced water needing to be transported through the region also increases, driving demand for all of our services. While competition continues to grow in the Williston Basin for gathering and processing services, growth in production provides opportunities for well-positioned operators. Because few of our competitors are full service providers, the fragmented competitive landscape provides consolidation opportunities for full service providers with substantial assets. Operators continue to increase rig and completion efficiency, reduce per well costs and achieve higher EURs, which has resulted in the maintenance of consistent production levels in the Williston Basin despite a lower commodity price environment. In the current commodity price environment, producers’ capital budgets are typically constrained and focused on production rather than infrastructure. As a result, producers will be incentivized to use existing infrastructure as opposed to developing the infrastructure internally.

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 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 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. With the improved drilling techniques, capital efficiency and

Index to Financial Statements

increasing EUR performance have continued to drive costs down in the area. Oasis currently has 518,000 net acres in the region, resulting in 3,073 highly economic locations. The below chart shows the growth in Bakken production in North Dakota since 2010:

A growing issue regarding natural gas production and the demand for natural gas gathering and production is flaring. Natural gas production in the Williston Basin has increased since 2010 and, as a result, flaring has become an environmental issue because it releases carbon dioxide, a GHG, into the atmosphere. Flaring results from a lack of natural gas gathering and processing capacity to meet the rise in production. During the last four years, there has been an increased focus on decreasing the percentage of natural gas being flared in the state of North Dakota due to the emergence of strict flaring regulations that incentivize operators to process their natural gas rather than flare it. These factors have resulted in an increased demand for natural gas gathering and processing services in the Williston Basin.

Index to Financial Statements

The following map shows the general location of the Williston Basin and the Bakken in the United States:

Index to Financial Statements

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 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 ROFO with respect to its retained interests in each of our DevCos or any other midstream assets that Oasis builds with respect to its current acreage and elects to sell in the future. 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.

Index to Financial Statements

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 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.

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

Index to Financial Statements

months ended December 31, 2016 took place on acreage dedicated to us. During the three months ended March 31, 2017, Oasis’s 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.

Index to Financial Statements

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.

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 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.

Index to Financial Statements

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

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:

Index to Financial Statements

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.

Index to Financial Statements

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 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.

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 IDRs. Oasis will also indirectly own 100% of Bighorn 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.

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

Index to Financial Statements

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.

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.

Index to Financial Statements

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.

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.

Index to Financial Statements

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.

The following commercial agreements will be entered into with certain wholly owned subsidiaries of Oasis. For purposes of the descriptions below, such subsidiaries are referred to as “Oasis.”

In connection with the closing of this offering, we will enter into a gas gathering, compression, processing and gas lift agreement with Oasis and OMS pursuant to which (1) Oasis will agree to deliver into our natural gas gathering system all of the natural gas produced that is owned or controlled by Oasis (subject to certain limited

Index to Financial Statements

exceptions) from a dedicated area consisting of 64,640 gross acres, of which 29,440 acres are within Oasis-operated DSUs, in the Wild Basin area and (2) we will perform certain gathering, compression, processing and gas lift services. The agreement will provide for an initial term of 15 years. With respect to gas processing, our contract provides that gas produced from the dedicated acreage, together with any third-party volumes, will be processed at our existing processing plant up to its working capacity.

In connection with the closing of this offering, we will enter into a crude oil agreement with Oasis and OMS pursuant to which (1) Oasis will agree to deliver into our crude oil gathering system all of the crude oil produced that is owned or controlled by Oasis (subject to certain limited exceptions) from a dedicated area consisting of 64,640 gross acres, of which 29,440 acres are within Oasis-operated DSUs, in the Wild Basin area and (2) we will perform certain gathering, stabilizing, blending and storing services for the crude oil delivered. The agreement will provide for an initial term of 15 years.

In connection with the closing of this offering, 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.

In connection with the closing of this offering, we will enter into a produced water gathering and disposal agreement with Oasis and OMS pursuant to which Oasis will dedicate 64,640 gross acres, of which 29,440 acres are within Oasis-operated DSUs, in the Wild Basin area to us for produced water gathering and disposal services. This agreement will provide for an initial term of 15 years.

Produced Water Gathering and Disposal Agreement—Alger, Cottonwood, Hebron, Indian Hills and Red Bank

In connection with the closing of this offering, we will enter into a produced water gathering and disposal agreement with Oasis and OMS pursuant to which Oasis will dedicate 597,760 gross acres, of which 305,024 acres are within Oasis-operated DSUs, in the Alger, Cottonwood, Hebron, Indian Hills and Red Bank operating areas to us for produced water gathering and disposal services. This agreement will provide for an initial term of 15 years.

In connection with the closing of this offering, we will enter into a freshwater distribution agreement with Oasis and OMS pursuant to which Oasis will purchase freshwater from us from time to time for use in its operations in the Hebron, Indian Hills and Red Bank operating areas, including but not limited to distributing freshwater for hydraulic fracturing and production optimization services. The agreement will provide for an initial term of 15 years.

In connection with the closing of this offering, we will enter into an omnibus agreement with Oasis, pursuant to which, among other things, Oasis will agree and will cause its affiliates to agree, for so long as Oasis or its affiliates, individually or as part of a group, control our general partner, that if Oasis or any of such affiliates decide to attempt to sell (other than to another affiliate of Oasis) the ROFO Assets, Oasis or its affiliate will notify us of its desire to sell such ROFO Assets and, prior to selling such ROFO Assets to a third party, will negotiate with us exclusively and in good faith for a period of days in order to give us an opportunity to enter into definitive agreements for the purchase and sale of such ROFO Assets on terms that are mutually acceptable

Index to Financial Statements

to Oasis or such affiliate and us. If we and Oasis or any of its affiliates have not entered into a letter of intent or a definitive purchase and sale agreement with respect to such ROFO Asset within such day period, or if any such letter of intent or agreement is entered into but subsequently terminated, then Oasis or such affiliate may, at any time during the succeeding day period, enter into a definitive transfer agreement with any third party with respect to such ROFO Assets on terms and conditions that, when taken as a whole, are superior, in the good faith determination of Oasis or such affiliate, to those set forth in the last written offer we had proposed during negotiations with Oasis or such affiliate, and Oasis or such affiliate has the right to sell such ROFO Asset pursuant to such transfer agreement.

The consideration to be paid by us for our ROFO Assets, as well as the consummation and timing of any acquisition by us of those assets, would depend upon, among other things, the timing of Oasis’s decision to sell those assets and our ability to successfully negotiate a price and other mutually agreeable purchase terms for those assets. Please read “Risk Factors—Risks Related to Our Business—We may be unable to grow by acquiring from Oasis the 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 flow” and “Certain Relationships and Related Party Transactions—Agreements with Affiliates in Connection with the Transactions—Omnibus Agreement” for more information regarding our ROFO Assets.

In connection with the completion of this offering, we will enter into a 15-year services and secondment agreement with Oasis, pursuant to which we will operate our midstream infrastructure, and Oasis will provide all personnel, equipment, electricity, chemicals, and services (including third-party services) required for us to operate such assets. We will reimburse Oasis for our share of the actual costs of operating such assets. We expect our operating costs will consist of the cost of equipment rental, labor, workovers and power, among other general operating costs. Pursuant to the services and secondment agreement, Oasis will, or will cause its affiliates to, perform centralized corporate, general and administrative services for us, such as legal, corporate recordkeeping, planning, budgeting, regulatory, accounting, billing, business development, treasury, insurance administration and claims processing, risk management, health, safety and environmental, information technology, human resources, investor relations, cash management and banking, payroll, internal audit, taxes and engineering. In addition to the provision of the general and administrative services, Oasis will also second to us certain of its employees to operate, construct, manage and maintain our assets. Our services and secondment agreement requires us to reimburse Oasis for direct general and administrative expenses incurred by Oasis for the provision of the above services. Additionally, we will reimburse Oasis for compensation and certain other expenses paid to employees of Oasis that are seconded to us and who spend time managing and operating our business. The expenses of executive officers and non-executive employees will be allocated to us based on the amount of time spent managing our business and operations. The reimbursements to our general partner and Oasis will be made prior to cash distributions to our common unitholders. We anticipate reimbursement to Oasis and its affiliates will vary with the size and scale of our operations, among other factors. We currently anticipate these reimbursable expenses will be approximately $ million for the twelve months ending June 30, 2018 based on our current operations, which includes $2.5 million of direct general and administrative expenses that we expect Oasis to incur on our behalf on an ongoing basis as a result of us becoming a publicly traded partnership. For more information about such fees and services, please read “Certain Relationships and Related Party Transactions—Agreements with Affiliates in Connection with the Transactions—Services and Secondment Agreement.”

As a result of the relationship between Oasis, OMS and our DevCos, we do not compete for the portion of Oasis’s existing operations for which we currently provide midstream infrastructure services. For areas where acreage is not dedicated to us, the DevCos will compete with similar enterprises in providing additional midstream infrastructure services in those areas of operation. Some of these competitors may expand or construct midstream infrastructure systems that would create additional competition for the services provided by the DevCos to oil and natural gas

Index to Financial Statements

producers. In addition, third parties that are significant producers of oil and natural gas in the DevCos’ areas of operation may develop their own midstream infrastructure systems in lieu of employing the DevCos’ services.

Substantially all of our interests in the real property on which our assets are located derive from leases, easements, rights-of-way, permits or licenses from landowners or governmental authorities, permitting the use of such land for our operations, and we believe that we have satisfactory interests in and to these lands. We have leased or acquired easements, rights-of-way, permits or licenses in these lands without any material challenge known to us relating to the title to the land upon which the assets will be located, and we believe that we have satisfactory interests in such lands. We have no knowledge of any challenge to the underlying fee title of any material lease, easement, right-of-way, permit or license held by us or to our title to any material lease, easement, right-of-way, permit or lease, and we believe that we have satisfactory title to all of our material leases, easements, rights-of-way, permits and licenses.

We carry a variety of insurance coverages for our operations. However, our insurance may not be sufficient to cover any particular loss or may not cover all losses, and losses not covered by insurance would increase our costs. Also, insurance rates are subject to fluctuation, so future insurance coverage could increase our costs. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that are economically acceptable, which could result in less coverage, increases in costs or higher deductibles and retentions.

Water and natural resource-related solid waste disposal involves several hazards and operational risks, including environmental damage from leaks, spills or vehicle accidents. To address the hazards inherent to our produced water gathering and disposal business, our insurance coverage includes commercial general liability, employer’s liability, commercial automobile liability, sudden and accidental pollution and other coverage. Coverage for environmental and pollution-related losses is subject to significant limitations and is commonly excluded on such policies.

Certain of our pipelines are subject to regulation by PHMSA under the HLPSA with respect to oil and the 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 HCAs, such as high population areas, areas unusually sensitive to environmental damage and commercially navigable waterways. In addition, states have adopted

Index to Financial Statements

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 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 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 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.

Our oil gathering and transportation, natural gas gathering and processing, and produced water gathering and disposal services and related operations are subject to stringent federal, state and local environmental laws and regulations relating to worker health and safety, the handling, discharge or disposal of materials and wastes, and the protection of natural resources and the environment. These laws and regulations may impose numerous obligations that are applicable to our and our oil and natural gas E&P customers’ operations, including, among other things, the acquisition of permits for regulated activities; the incurrence of capital or operating expenditures to limit or prevent releases of materials from operations; a limitation on the amounts and types of substances that

Index to Financial Statements

may be released into the environment in connection with operations; a restriction on the way wastes are handled or disposed; a limitation or prohibition on activities in sensitive areas such as wetlands, wilderness areas or areas inhabited by endangered or threatened species; the imposition of investigatory and remedial actions to prevent or mitigate pollution conditions caused by operations or attributable to former operations; the imposition of specific safety and health standards addressing worker protections; and the imposition of substantial liabilities for pollution resulting from operations. Numerous governmental agencies, including the EPA, OSHA and analogous state agencies, issue regulations to implement and enforce these laws, for which compliance is often costly and difficult. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil and criminal penalties, the imposition of investigatory, remedial and corrective action obligations or the denial or revocation of permits, loss of leases and the issuance of injunctions limiting some or all of our operations in a particular area.

The trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and thus, any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly well drilling, construction, completion or water management activities, or waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on our financial position and results of operations. While we occasionally receive citations from regulatory agencies for violations of environmental laws and regulations, such citations have been issued in the ordinary course of our business and have not been material to our operations. Historically, our environmental 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 will not have a material adverse effect on our business and operating results. We may be unable to pass on such increased compliance costs to our customers. Additionally, accidental spills or other releases may occur in the course of our operations and we cannot be sure that we will not incur significant costs and liabilities as a result of such spills or releases, including any third-party claims for damage to property, natural resources or persons.

Moreover, our customers are also subject to these same laws and regulations. Any changes in environmental laws could limit our customers’ businesses or encourage our customers to handle and dispose of wastes in other ways, which, in either case, could reduce the demand for our gathering, transportation, processing and disposal services and adversely impact our business. While compliance with some environmental laws and regulations creates a need for assets such as our own, other environmental laws and regulations could reduce the demand for our services. For instance, some states have considered laws mandating the recycling of flowback water and produced water generated by oil and natural gas development and production activities. If such laws are passed, our customers may divert some flowback water and produced water to recycling operations that may have otherwise been disposed of at our facilities.

The following is a summary of the more significant existing environmental and occupational health and safety laws and regulations, as amended from time to time, to which our business operations and the operations of our customers are subject and for which compliance in the future may have a material adverse impact on our capital expenditures, results of operations, or financial position.

Our operations are subject to environmental laws and regulations relating to the management and release of hazardous substances, non-hazardous wastes, hazardous wastes and petroleum hydrocarbons. These laws generally regulate the generation, storage, treatment, transportation and disposal of non-hazardous and hazardous waste and may impose strict joint and several liability for the investigation and remediation of affected areas where hazardous substances may have been released or disposed. The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), also known as the Superfund law, and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have caused or contributed to the release of a “hazardous substance” into the environment. These persons include the current and past owners or operators of the disposal site or the site where the release

Index to Financial Statements

occurred and entities that disposed or arranged for the disposal of the hazardous substances at the site where the release occurred. Under CERCLA, such persons may be subject to joint and several, strict liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. We handle materials that may be regulated as hazardous substances within the meaning of CERCLA, or similar state statutes, in the course of our ordinary operations, but we are unaware of any liabilities for which we may be held responsible that would materially and adversely affect us.

We also generate as well as accept for disposal from our customers wastes that are subject to the requirements of the Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes. RCRA regulates the generation, storage, treatment, transportation and disposal of both non-hazardous and hazardous wastes, but it imposes more stringent requirements on the management of hazardous wastes. In the course of our or our customers’ operations, some amounts of ordinary industrial wastes are generated that may be regulated as hazardous wastes. Most E&P waste, if properly handled, is exempt from regulation as a hazardous waste under RCRA. However, it is possible that certain E&P waste now classified as non-hazardous waste and exempt from treatment as hazardous wastes may in the future be designated as “hazardous wastes” under RCRA or other applicable statutes. For example, following the filing of a lawsuit in the U.S. District Court for the District of Columbia in May 2016 by several non-governmental environmental groups against the EPA for the agency’s failure to timely assess its RCRA Subtitle D criteria regulations for oil and gas wastes, EPA and the environmental groups entered into an agreement that was finalized in a consent decree issued by the District Court in December 2016. Under the decree, the EPA is required to propose no later than March 15, 2019, a rulemaking for revision of certain Subtitle D criteria regulations pertaining to oil and gas wastes or sign a determination that revision of the regulations is not necessary. If EPA proposes a rulemaking for revised oil and gas waste regulations, the Consent Decree requires that the EPA take final action following notice and comment rulemaking no later than July 15, 2021. If the RCRA E&P waste exemption is repealed or modified, we and our customers could become subject to more rigorous and costly operating and disposal requirements, which could have a material adverse effect on our results of operations and financial position.

We currently own, lease, or operate upon a number of properties that have been used for oil and natural gas exploration, development and production support-service activities for many years. Although we believe that we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes or petroleum hydrocarbons may have been released on, under or from the properties owned or leased by us, or on, under or from other locations, including off-site locations, where such substances have been taken for treatment or disposal. In addition, some of our properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes or petroleum hydrocarbons was not under our control. These properties and the substances disposed or released on, under or from them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to undertake response or corrective measures, which could include removal of previously disposed substances and wastes, cleanup of contaminated property or performance of remedial closure operations to prevent future contamination, the costs of which could be material.

In the course of our operations, some of our storage and process vessels, piping work areas and other equipment may be exposed to naturally occurring radioactive material (“NORM”) associated with oil and natural gas production. NORM-contaminated scale deposits and other accumulations exhibiting trace levels of naturally occurring radiation in excess of established state standards are subject to special handling and disposal requirements, and any storage and process vessels, piping and work areas affected by NORM may be subject to remediation or restoration requirements. It is possible that we may incur costs or liabilities associated with elevated levels of NORM.

Index to Financial Statements

Our produced water underground injection operations are subject to the SDWA as well as analogous state laws and regulations. Under the SDWA, the EPA established the UIC program, which established the minimum program requirements for state and local programs regulating underground injection activities. The UIC program includes requirements for permitting, testing, monitoring, record keeping and reporting of injection well activities, as well as a prohibition against the migration of fluid containing any contaminant into underground sources of drinking water. State regulations require us to obtain a permit from the applicable regulatory agencies to operate our underground injection wells. States may add more stringent restrictions on the operation of injection wells when a permit is renewed or amended, which may require material expenditures at our facilities or impose significant restraints or financial assurances on our operations.

Although we monitor the injection process of our wells, any leakage from the subsurface portions of the injection wells could cause degradation of fresh groundwater resources, potentially resulting in suspension of our UIC permit, issuance of fines and penalties from governmental agencies, incurrence of expenditures for remediation of the affected resource and imposition of liability by third-parties claiming damages for alternative water supplies, property damages and personal injuries. Also, some states have considered laws mandating the recycling of flowback and produced water. If such laws are adopted in areas where we conduct our operations, our operating costs may increase significantly. In addition, our sales of residual crude oil collected as part of the produced water injection process may impose liability on us in the event that the entity to which the crude oil was transferred fails to manage and dispose of residual crude oil in accordance with applicable environmental and occupational health and safety laws.

There exists a growing concern that the injection of produced water into belowground disposal wells may trigger seismic activity. 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 E&P customers, such as by limiting volumes, disposal rates, disposal well locations or otherwise, or by requiring us to shut down disposal wells, could have a material adverse effect on our business, financial condition and results of operations.

The Federal Water Pollution Control Act (“Clean Water Act”) and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants into state waters as well as waters of the United States and impose requirements affecting our ability to conduct activities in waters and wetlands. Pursuant to the Clean Water Act and analogous state laws, permits must be obtained to discharge pollutants into state waters or waters of the United States, and permits or coverage under general permits must also be obtained to authorize discharges of storm water runoff from certain types of industrial facilities. Spill prevention, control and countermeasure requirements of federal laws require appropriate containment berms and similar structures to help prevent the contamination of regulated waters in the event of a hydrocarbon storage tank spill, rupture or leak. The Clean Water Act and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by a permit issued by the U.S. Army Corps of Engineers (the “Corps”). In September 2015, the EPA and the Corps issued final rules outlining their position on the federal jurisdictional reach over waters of the United States, but this rule has been stayed nationwide by the U.S. Sixth Circuit Court of Appeals as that appellate court and numerous district courts ponder lawsuits opposing implementation of the rule. In January 2017, the United States Supreme Court accepted review of the rule to determine whether jurisdiction rests with the federal district or appellate courts. Litigation surrounding this rule is ongoing. In February 2017, President Trump issued an executive order directing the EPA and the

Index to Financial Statements

Corps to review and, consistent with applicable law, initiative rulemaking to rescind or revise the rule. The EPA and the Corps published a notice of intent to review and rescind or revise the rule in March 2017. Additionally, the U.S. Department of Justice filed a motion with the U.S. Supreme Court in March 2017 requesting the court stay the suit concerning which courts should hear challenges to the rule. At this time, it is unclear what impact these actions will have on the implementation of the rule. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations.

The primary federal law related specifically to oil spill liability is the Oil Pollution Act of 1990 (“OPA”), which establishes strict, joint and several liability for certain responsible parties in connection releases of crude oil into waters of the United States. The OPA also imposes ongoing requirements on owners and operators of certain oil and natural gas facilities that handle certain quantities of oil, including the preparation of oil spill response plans and proof of financial responsibility to cover environmental cleanup and restoration costs that could be incurred in connection with an oil spill. If a release of oil into the waters of the United States occurred, we could be liable for clean-up costs and various damages under the OPA.

The CAA and comparable state laws, regulate emissions of various air pollutants through air emissions standards, construction and operating permitting programs and the imposition of other compliance requirements. These laws and regulations may require us or our oil and natural gas E&P customers to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions of certain pollutants. The need to obtain permits has the potential to delay the expansion of our projects as well as our customers’ development of oil and natural gas projects. Failure to obtain a permit or to comply with permit requirements could result in the imposition of administrative, civil and criminal penalties.

Recently, there has been increased regulation with respect to air emissions resulting from the oil and natural gas sector. For example, in October 2015, the EPA issued a final rule under the CAA, lowering the National Ambient Air Quality Standard for ground-level ozone to 70 parts per billion under both the primary and secondary standards. State implementation of these revised standards could result in stricter permitting requirements, delay or prohibit our ability to obtain such permits and result in increased expenditures for pollution control equipment, the costs of which could be significant. Also, the EPA finalized separate rules under the CAA in June 2016 regarding criteria for aggregating multiple sites into a single source for air-quality permitting purposes applicable to the oil and gas industry. This rule could cause small production facilities (such as tank batteries and compressor stations), on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting requirements for our customers that, in turn, could result in operational delays or the installation of costly pollution control equipment, which developments could reduce the demand for our services.

In addition, with respect to our customers, the EPA has adopted new rules under the CAA that require the reduction of volatile organic compound emissions from certain fractured and re-fractured natural gas wells for which well completion operations are conducted and, for certain of those wells, require the use of reduced emission completions, also known as “green completions.” These regulations also establish specific new requirements regarding emissions from production-related wet seal and reciprocating compressors and from pneumatic controllers and storage vessels. In addition, the regulations place new requirements to detect and repair volatile organic compound and methane at certain well sites and compressor stations. Compliance with one or more of these requirements could significantly increase our customers’ costs of operations and costs incurred in developing and producing petroleum hydrocarbons. Such increases could lead to reduced operations by our customers and, as a result, may have an adverse effect on the amount of oil, natural gas or produced water from our customers that is gathered, transported, processed and/or disposed by us.

Index to Financial Statements

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 of cap-and-trade programs, carbon taxes and 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. The EPA has, however, adopted rules under authority of the CAA that, among other things, establish permitting reviews for GHG emissions from certain large stationary sources that are also potential major sources of certain principal pollutant emissions, which reviews could require meeting “best available control technology” standards for those emissions. In addition, the EPA has adopted rules requiring the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the United States, including specified onshore and offshore production facilities and onshore 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 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 previously issued NSPS published by the EPA in 2012 and known as Subpart OOOO, by using certain equipment-specific emissions control practices. Moreover, in November 2016, the EPA issued an ICR, seeking information about methane emissions from facilities and operators in the oil and natural gas industry, but, in March 2017, the EPA announced that it was withdrawing the ICR so that the agency may 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 preparing an agreement requiring member countries to review and “represent a progression” in their intended nationally determined contributions, which 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; however, this agreement does not create any binding obligations for nations to limit their GHG emissions, but rather includes pledges to voluntarily limit or reduce future emissions. With the changes 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 or regulations that require reporting of GHGs, or otherwise limit emissions of GHGs from our equipment and operations, could require us to incur costs to reduce emissions of GHGs associated with our operations, as well as cause delays or restrictions in our ability to permit GHG emissions from new or modified sources. In addition, substantial limitations on GHG emissions could adversely affect demand for the oil and natural gas our customers produce and lower the value of their reserves, which devaluation could reduce demand for our services.

Finally, it should be noted 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 any such effects were to occur, they could have an adverse effect on our customers’ E&P operations and reduce demand for our services. 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.

Hydraulic fracturing is an important common practice that is used to stimulate production of hydrocarbons, including oil and natural gas, from low permeability formations, including shales. The process involves the injection of water, sand and chemicals under pressure into targeted formations to fracture the surrounding rock and stimulate production. Our customers regularly use hydraulic fracturing as part of their operations. Hydraulic fracturing is currently generally exempt from regulation under the SDWA’s UIC program and is typically regulated by state oil and natural gas commissions and similar agencies. However, several federal agencies have

Index to Financial Statements

conducted investigations or asserted regulatory authority over certain aspects of the process. For example, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The final report concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources under some circumstances. Additionally, in February 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 May 2014, the EPA issued an Advance Notice of Proposed Rulemaking to collect data on chemicals used in hydraulic fracturing operations under Section 8 of the Toxic Substances Control Act; in June 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; and, in March 2015, the BLM published a final rule that established new or more stringent standards relating to hydraulic fracturing on federal and American Indian lands, but that 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 imposing new permitting, disclosure, disposal and well construction requirements on hydraulic fracturing operations. States could impose moratoriums or elect to prohibit high-volume hydraulic fracturing altogether, similar to the approach taken by the State of New York in 2015. Also, local governments could 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, our and our customers’ fracturing activities could become subject to additional permit requirements, reporting requirements, operational restrictions, permitting delays or additional costs. Any such laws or regulations could adversely affect the determination of whether a well is commercially viable and reduce the amount of oil and natural gas that our customers are ultimately able to produce in commercial quantities, and thus significantly affect our business. Such laws and regulations could also materially increase our cost of business by more strictly regulating how hydraulic fracturing wastes are handled or disposed.

Oil and natural gas E&P activities on federal lands are subject to the National Environmental Policy Act (“NEPA”). NEPA requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. The process involves the preparation of either an environmental assessment or environmental impact statement depending on whether the specific circumstances surrounding the proposed federal action will have a significant impact on the human environment. The NEPA process involves public input through comments, which can alter the nature of a proposed project either by limiting the scope of the project or requiring resource-specific mitigation. NEPA decisions can be appealed through the court system by process participants. This process may result in delaying the permitting and development of projects, increase the costs of permitting and developing some facilities and could result in certain instances in the cancellation of existing leases.

The Endangered Species Act (“ESA”) and analogous state laws restrict activities that may affect endangered or threatened species or their habitats. Similar protections are offered to migratory birds under the Migratory Birds Treaty Act. To the extent species that are listed under the ESA or similar state laws live in the areas where our operations and our customers’ operations are conducted, our and our customers’ abilities to conduct or

Index to Financial Statements

expand operations and construct facilities could be limited or could force us to incur significant additional costs. In February 2016, the U.S. Fish and Wildlife Service (“FWS”) published a final policy which alters how it may designate critical habitat and suitable habitat areas that it believes are necessary for survival of a threatened or endangered species. A critical habitat or suitable habitat designation could result in further material restrictions to land use and may materially delay or prohibit land access for oil and natural gas development. In addition, as a result of one or more settlements entered into by the FWS, the agency is required to make numerous determinations on the listing of species as endangered or threatened under the ESA pursuant to a set timeline. For example, in 2015, the FWS listed the northern long-eared bat, whose range includes North Dakota and parts of Montana, as a threatened species under the ESA. The designation of previously undesignated species as endangered or threatened could cause us to incur additional costs or cause our customers’ operations to become subject to operating restrictions or bans or limit future development activity in affected areas, which developments could reduce demand for our gathering, transportation, processing and disposal services.

We are subject to the requirements of the federal OSHA and comparable state laws that regulate the protection of employee health and safety. In addition, OSHA’s hazard communications standard, the Emergency Planning and Community Right-to-Know Act, requires that information about hazardous materials used or produced in our operations be maintained and provided to employees, state and local government authorities and citizens. These laws and regulations are subject to frequent changes. Failure to comply with these laws could lead to the assertion of third-party claims against us, civil or criminal fines and changes in the way we operate our facilities that could have an adverse effect on our financial position. Furthermore, 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.

The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations that are binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although changes to the regulatory burden on the oil and natural gas industry could affect the demand for our services, we would not expect to be affected any differently or to any greater or lesser extent than other companies in the industry with similar operations.

States regulate the drilling for oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and natural gas resources. For example, in July 2014, the North Dakota Industrial Commission adopted the July 2014 Order, pursuant to which the agency adopted legally enforceable “gas capture percentage goals” targeting the capture of 74% of the natural gas produced in the state by October 1, 2014, 77% 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. Modifications of the July 2014 Order were announced by the North Dakota Industrial Commission 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

Index to Financial Statements

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, they 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.

States do not regulate wellhead prices or engage in other similar direct economic regulation, but we cannot assure you that they will not do so in the future. The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect on us.

We do not have any employees. The officers of our general partner, who are also officers of Oasis, will manage our operations and activities. As of March 31, 2017, Oasis employed approximately 50 people who will provide direct, full-time support to our operations. All of the employees that conduct our business are employed by Oasis and its affiliates. We believe that Oasis and its affiliates have a satisfactory relationship with those employees.

Our operations are subject to a variety of risks and disputes normally incident to our business. As a result, we may, at any given time, be a defendant in various legal proceedings and litigation arising in the ordinary course of business. However, except as disclosed below we are not currently subject to any potentially material litigation.

We maintain insurance policies with insurers in amounts and with coverage and deductibles that we, with the advice of our insurance advisors and brokers, believe are reasonable and prudent. We cannot, however, assure you that this insurance will be adequate to protect us from all material expenses related to potential future claims for personal and property damage or that these levels of insurance will be available in the future at economical prices.

On March 23, 2017, Mirada Energy, LLC, Mirada Wild Basin Holding Company, LLC and Mirada Energy Fund I, LLC (collectively, “Mirada”) filed a lawsuit against Oasis, OPNA and OMS, seeking monetary damages in excess of $100 million, declaratory relief, attorneys’ fees and costs (Mirada Energy, LLC, et al. v. Oasis Petroleum North America LLC, et al.; in the 334th Judicial District Court of Harris County, Texas; Case Number 2017-19911). Mirada asserts that it is a working interest owner in certain acreage owned and operated by Oasis in Wild Basin. Specifically, Mirada asserts that Oasis has breached certain agreements by: (1) failing to allow Mirada to participate in Oasis’s midstream operations in Wild Basin; (2) refusing to provide Mirada with information that Mirada contends is required under certain agreements and failing to provide information in a timely fashion; (3) failing to consult with Mirada and failing to obtain Mirada’s consent prior to drilling more than one well at a time in Wild Basin; and (4) by overstating the estimated costs of proposed well operations in Wild Basin. Mirada seeks a declaratory judgment that OPNA be removed as operator in Wild Basin at Mirada’s election and that Mirada be allowed to elect a new operator; certain agreements apply to Oasis and Mirada and Wild Basin with respect to this dispute; Oasis be required to provide all information within its possession regarding proposed or ongoing operations in Wild Basin; and OPNA not be permitted to drill, or propose to drill, more than one well at a time in Wild Basin without obtaining Mirada’s consent. Mirada also seeks a declaratory judgment with respect to Oasis’s current midstream operations in Wild Basin. Specifically, Mirada seeks a declaratory judgment that Mirada has a right to participate in Oasis’s Wild Basin midstream operations,

Index to Financial Statements

consisting of produced water disposal, crude oil gathering and gas gathering and processing; that, upon Mirada’s election to participate, Mirada is obligated to pay its proportionate costs of Oasis’s midstream operations in Wild Basin; and that Mirada would then be entitled to receive a share of revenues from the midstream operations and would not be charged any amount for its use of these facilities for production from the “Contract Area.”

Oasis believes that Mirada’s claims are without merit, that Oasis has complied with its obligations under the applicable agreements and that some of Mirada’s claims are grounded in agreements which do not apply to Oasis. Oasis filed an answer denying Mirada’s claims on April 21, 2017, and intends to vigorously defend against Mirada’s claims and, to the extent we are made a party to the suit, we intend to vigorously defend ourselves against such claims. Discovery is ongoing. Trial is currently scheduled for July 2018. However, neither we nor Oasis can predict or guarantee the ultimate outcome or resolution of such matter. If such matter 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.

On February 5, 2016, the North Dakota Department of Health issued a Notice of Violation to OPNA in respect of a release that occurred on or about May 4, 2015 on a pipeline serving the Hegstad SWD 6092 41-20. The pipeline, which is among the assets contributed to us, experienced a release of produced water and some crude oil. The North Dakota Department of Health has proposed a penalty of approximately $0.1 million as a result of the release.

Index to Financial Statements

We will be managed and operated by the board of directors and executive officers of our general partner upon the consummation of this offering. Our general partner is controlled by Oasis. All of our officers and certain of our directors are also officers and/or directors of Oasis. Neither our general partner nor its board of directors will be elected by our unitholders and none will be subject to re-election in the future. OMS Holdings, a wholly owned subsidiary of Oasis, is the sole member of our general partner and will have the right to appoint our general partner’s entire board of directors, including at least three independent directors meeting the independence standards established by the NYSE. At least of our independent directors will be appointed prior to the date our common units are listed for trading on the NYSE. Our unitholders will not be entitled to directly or indirectly participate in our management or operations. Our general partner owes certain contractual duties to our unitholders as well as a fiduciary duty to its owners.

Upon the closing of this offering, we expect that our general partner will have directors. The NYSE does not require a listed publicly traded partnership, such as ours, to have a majority of independent directors on the board of directors of our general partner or to establish a compensation committee or a nominating committee. However, our general partner is required to have an audit committee of at least three members, and all its members are required to meet the independence and experience standards established by the NYSE and the Exchange Act, subject to certain transitional relief during the one-year period following the completion of this offering. Oasis, through its ownership of OMS Holdings, will appoint at least one member of the audit committee to the board of directors of our general partner by the date our common units first trade on the NYSE .

In evaluating director candidates, Oasis will assess whether a candidate possesses the integrity, judgment, knowledge, experience, skill and expertise that are likely to enhance the board’s ability to manage and direct our affairs and business, including, when applicable, to enhance the ability of committees of the board to fulfill their duties.

All of the executive officers of our general partner listed below will allocate their time between managing our business and affairs and the business and affairs of Oasis. The amount of time that our executive officers will devote to our business and the business of Oasis will vary in any given year based on a variety of factors. Our executive officers intend, however, to devote as much time to the management of our business and affairs as is necessary for the proper conduct of our business and affairs.

Following the consummation of this offering, Oasis shall provide customary management and general administrative services to us pursuant to an omnibus agreement. Our general partner shall reimburse Oasis at cost for its direct expenses incurred on behalf of us and a proportionate amount of its indirect expenses incurred on behalf of us, including, but not limited to, compensation expenses. Neither our general partner nor Oasis will receive any management fee or other compensation. 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 read “Certain Relationships and Related Party Transactions—Agreements with Affiliates in Connection with the Transactions.”

Index to Financial Statements

The following table shows information for the executive officers and directors of our general partner as of March 31, 2017. Directors hold office until their successors have been elected or qualified or until the earlier of their death, resignation, removal or disqualification. Executive officers serve at the discretion of the board. Some of the directors and executive officers of our general partner also serve as executive officers and/or directors of Oasis.

Thomas B. Nusz is the Chairman of the board of directors of our general partner. He has served as Oasis’s Director and Chief Executive Officer since March 2007. He has also served as Oasis’s President until January 1, 2014, and has 35 years of experience in the oil and gas industry. From April 2006 to February 2007, Mr. Nusz managed his personal investments, developed the business plan for Oasis Petroleum LLC and secured funding for the Company. He was previously a Vice President with Burlington Resources Inc., a formerly publicly traded oil and gas E&P company or, together with its predecessors, Burlington, and served as President International Division (North Africa, Northwest Europe, Latin America and China) from January 2004 to March 2006, as Vice President Acquisitions and Divestitures from October 2000 to December 2003 and as Vice President Strategic Planning and Engineering from July 1998 to September 2000 and Chief Engineer for substantially all of such period. He was instrumental in Burlington’s expansion into the Western Canadian Sedimentary Basin from 1999 to 2002. From September 1985 to June 1998, Mr. Nusz held various operations and managerial positions with Burlington in several regions of the United States, including the Permian Basin, the San Juan Basin, the Black Warrior Basin, the Anadarko Basin, onshore Gulf Coast and Gulf of Mexico. Mr. Nusz was an engineer with Mobil Oil Corporation and for Superior Oil Company from June 1982 to August 1985. He is a current member of the National Petroleum Council, an advisory committee to the Secretary of Energy of the United States. Mr. Nusz holds a Bachelor of Science in Petroleum Engineering from Mississippi State University.

Taylor L. Reid is the Chief Executive Officer and Director of our general partner. He has served as Oasis’s Director, President and Chief Operating Officer since January 1, 2014. He served as Oasis’s Director, Executive Vice President and Chief Operating Officer (or in similar capacities) since Oasis’s inception in March 2007 and has 32 years of experience in the oil and gas industry. From November 2006 to February 2007, Mr. Reid worked with Mr. Nusz to form the business plan for Oasis Petroleum LLC and secure funding for the Company. He previously served as Asset Manager Permian and Panhandle Operations with ConocoPhillips from April 2006 to October 2006. Prior to joining ConocoPhillips, he served as General Manager Latin America and Asia Operations with Burlington from March 2004 to March 2006 and as General Manager Corporate Acquisitions and Divestitures from July 1998 to February 2004. From March 1986 to June 1998, Mr. Reid held various operations and managerial positions with Burlington in several regions of the continental United States, including the Permian Basin, the Williston Basin and the Anadarko Basin. He was instrumental in Burlington’s expansion into the Western Canadian Sedimentary Basin from 1999 to 2002. Mr. Reid holds a Bachelor of Science in Petroleum Engineering from Stanford University.

Michael H. Lou is the President and Director of our general partner. He has served as Oasis’s Executive Vice President and Chief Financial Officer since August 2011. Mr. Lou served as Oasis’s Senior Vice President Finance (or similar capacities) from September 2009 to August 2011 and has 20 years of experience in the oil and gas industry. Prior to joining us, Mr. Lou was an independent contractor from January 2009 to August 2009. From February 2008 to December 2008, he served as the Chief Financial Officer of Giant Energy Ltd., a private

Index to Financial Statements

oil and gas management company; from July 2006 to December 2008 he served as Chief Financial Officer of XXL Energy Corp., a publicly listed Canadian oil and gas company; and from August 2008 to December 2008, he served as Vice President Finance of Warrior Energy N.V., a publicly listed Canadian oil and gas company. From October 2005 to July 2006, Mr. Lou was a Director for Macquarie Investment Bank. Prior to joining Macquarie, Mr. Lou was a Vice President for First Albany Investment Banking from 2004 to 2006. From 1999 to 2004, Mr. Lou held positions of increasing responsibility, most recently as a Vice President, for Bank of America’s investment banking group. From 1997 to 1999, Mr. Lou was an analyst for Merrill Lynch’s investment banking group. Mr. Lou holds a Bachelor of Science in Electrical Engineering from Southern Methodist University.

Nickolas J. Lorentzatos is the Executive Vice President, General Counsel and Corporate Secretary and Director of our general partner. He has served as Oasis’s Executive Vice President, General Counsel and Corporate Secretary since January 1, 2014. Mr. Lorentzatos served as Oasis’s Senior Vice President, General Counsel and Corporate Secretary from September 2010 to December 31, 2013, and has 17 years of experience in the oil and gas industry and 21 years practicing law. He previously served as Senior Counsel with Targa Resources from July 2007 to September 2010. From April 2006 to July 2007, he served as Senior Counsel to ConocoPhillips. Prior to the merger of Burlington Resources Inc. and ConocoPhillips which became effective in 2006, he served as Counsel and Senior Counsel to Burlington since August 1999. From September 1995 to August 1999, he was an associate with Bracewell & Patterson, LLP. Mr. Lorentzatos holds a Bachelor of Arts from Washington and Lee University, a Juris Doctor from the University of Houston, and a Masters of Business Administration from the University of Texas at Austin.

Richard N. Robuck is the Senior Vice President and Chief Financial Officer of our general partner. He has served as Oasis’s Senior Vice President Finance and Treasurer since January 2017. Previously, Mr. Robuck served as Vice President Finance and Treasurer (or similar capacities) since April 2010. Mr. Robuck began his career 19 years ago in the oil and gas industry at Bank of America in their Energy Group. Prior to joining Oasis, Mr. Robuck was VP – Finance and Investments at Southern Ute Alternative Energy from October 2008 until April 2010. From July 2001 to October 2008, he served in various financial capacities at Grande Communications, a private telecommunications company in Austin, Texas, serving as VP-Finance from April 2005 through October 2008. Mr. Robuck holds a Bachelor of Business Administration from The University of Texas at Austin and a Master of Business Administration from Rice University.

We expect that the board of directors of our general partner will have an audit committee and a conflicts committee. We do not expect that we will have a compensation committee, but rather that our board of directors will approve equity grants to directors and employees.

Our general partner will establish an audit committee prior to the completion of this offering. Rules implemented by the NYSE and SEC require us to have an audit committee comprised of at least three directors who meet the independence and experience standards established by the NYSE and the Exchange Act, subject to transitional relief during the one-year period following the completion of this offering. As required by the rules of the SEC and listing standards of the NYSE, the audit committee will consist solely of independent directors, subject to transitional relief. We anticipate that following the completion of this offering, our audit committee will initially consist of who will be independent under the rules of the SEC. Subsequent to the transitional period, we will comply with the requirement to have three independent directors. SEC rules also require that a public company disclose whether or not its audit committee has an “audit committee financial expert” as a member. An “audit committee financial expert” is defined as a person who, based on his or her experience, possesses the attributes outlined in such rules. Our board of directors believes satisfies the definition of “audit committee financial expert.”

Index to Financial Statements

This committee will oversee, review, act on and report on various auditing and accounting matters to our board of directors, including: the selection of our independent accountants, the scope of our annual audits, fees to be paid to the independent accountants, the performance of our independent accountants and our accounting practices. In addition, the audit committee will oversee our compliance programs relating to legal and regulatory requirements. We expect to adopt an audit committee charter defining the committee’s primary duties in a manner consistent with the rules of the SEC and NYSE.

At least one independent member of the board of directors of our general partner will serve on a conflicts committee to review specific matters that the board believes may involve conflicts of interest and determines to submit to the conflicts committee for review. The conflicts committee will determine if the resolution of the conflict of interest is adverse to the interest of the partnership. There is no requirement that our general partner seek the approval of the conflicts committee for the resolution of any conflict. The members of the conflicts committee may not be officers or employees of our general partner or directors, officers or employees of its affiliates, including Oasis, and must meet the independence and experience standards established by the NYSE and the Exchange Act to serve on an audit committee of a board of directors, along with other requirements in our partnership agreement. Any matters approved by the conflicts committee will be conclusively deemed to be approved by us and all of our partners and not a breach by our general partner of any duties it may owe us or our unitholders.

Index to Financial Statements

Prior to the closing of this offering, we and our general partner had no material assets or operations. Accordingly, neither we nor our general partner incurred any cost or liability with respect to management compensation or retirement benefits for directors or executive officers for any periods prior to the completion of this offering. As a result, we have no historical compensation information to present.

We do not directly employ any of the persons responsible for managing our business. We are managed and operated by our general partner. All of the executive officers of our general partner will be employed and compensated by Oasis or one of its subsidiaries. All of the initial executive officers who will be responsible for managing our day-to-day affairs are also current officers of Oasis and will have responsibilities to both us and Oasis, and we expect that our executive officers will allocate their time between managing our business and managing the business of Oasis. The amount of time that our executive officers will devote to our business and the business of Oasis will vary in any given year based on a variety of factors. Our executive officers intend, however, to devote as much time to the management of our business and affairs as is necessary for the proper conduct of our business and affairs.

Since all of our executive officers will be employed by Oasis or one of its subsidiaries, the responsibility and authority for compensation-related decisions for our executive officers will reside with the Oasis’s board of directors or compensation committee. Any such compensation decisions will not be subject to any approvals by the board of directors of our general partner or any committees thereof. However, all determinations with respect to awards that may be made to our executive officers, key employees and independent directors under any equity incentive plan we adopt will be made by the board of directors of our general partner or a committee thereof that may be established for such purpose. Please see the description of the long-term equity incentive plan we intend to adopt prior to the completion of this offering (“LTIP”) below under the heading “Long-Term Incentive Plan.”

The executive officers of our general partner, as well as the employees of Oasis who provide services to us, may participate in employee benefit plans and arrangements sponsored by Oasis, including plans that may be established in the future. Certain executive officers and employees who provide services to us currently hold awards under Oasis’s equity incentive plan and will continue to hold such awards following the completion of this offering. Further, certain of our executive officers currently have employment agreements with Oasis that we anticipate will continue in effect following the completion of this offering.

Except with respect to any awards that may be granted under the LTIP, we do not anticipate that our executive officers will receive separate amounts of compensation in relation to the services they provide to us. In accordance with the terms of our partnership agreement and our services and secondment agreement, we will reimburse Oasis for compensation- related expenses attributable to the portion of the executive officer’s time dedicated to providing services to us, including expenses for salary, bonus, incentive compensation and other amounts paid. Please read “The Partnership Agreement—Reimbursement of Expenses” and “Certain Relationships and Related Party Transactions—Agreements with Affiliates in Connection with the Transactions—Services and Secondment Agreement.” Although we will bear an allocated portion of Oasis’s costs of providing compensation and benefits to employees who serve as executive officers of our general partner, we will have no control over such costs and will not establish or direct the compensation policies or practices of Oasis.

We expect that future compensation for our executive officers will continue to be structured in a manner similar to that currently used by Oasis to compensate its executive officers, which is described in greater detail with respect to the named executive officers of Oasis in Oasis’s definitive proxy statement on Schedule 14A (file no: 001-34776), filed with the Securities and Exchange Commission on March 22, 2017.

Our general partner does not currently have a compensation committee. Our general partner may establish a compensation committee prior to the closing of this offering.

Index to Financial Statements

In order to incentivize our management and directors following the completion of this offering to continue to grow our business, the board of directors of our general partner intends to adopt a long term incentive plan, or the LTIP, for employees, officers, consultants and directors of our general partner and any of its affiliates, including Oasis, who perform services for us. Our general partner intends to implement the LTIP prior to the completion of this offering to provide maximum flexibility with respect to the design of compensatory arrangements for individuals providing services to us; however, at this time, neither we nor our general partner has made any decisions regarding any specific grants under the LTIP in conjunction with this offering or in the near term.

The description of the LTIP set forth below is a summary of the material features of the LTIP that our general partner intends to adopt. This summary, however, does not purport to be a complete description of all the provisions of the LTIP that will be adopted and represents only the general partner’s current expectations regarding the LTIP. This summary is qualified in its entirety by reference to the LTIP, the form of which is filed as an exhibit to this registration statement. The purpose of the LTIP is to provide a means to attract and retain individuals who are essential to our growth and profitability and to encourage them to devote their best efforts to advancing our business by affording such individuals a means to acquire and maintain ownership of awards, the value of which is tied to the performance of our common units. We expect that the LTIP will provide for the grant of unit options, unit appreciation rights, restricted units, unit awards, phantom units, distribution equivalent rights, cash awards, performance awards, other unit-based awards and substitute awards (collectively, “awards”). These awards are intended to align the interests of employees, officers, consultants and directors with those of our unitholders and to give such individuals the opportunity to share in our long term performance. Any awards that are made under the LTIP will be approved by the board of directors of our general partner or a committee thereof that may be established for such purpose. We will be responsible for the cost of awards granted under the LTIP.

The LTIP will be administered by the board of directors of our general partner or an alternative committee appointed by the board of directors of our general partner, which we refer to together as the “committee” for purposes of this summary. The committee will administer the LTIP pursuant to its terms and all applicable state, federal, or other rules or laws. The committee will have the power to determine to whom and when awards will be granted, determine the amount of awards (measured in cash or our common units), proscribe and interpret the terms and provisions of each award agreement (the terms of which may vary), accelerate the vesting provisions associated with an award, delegate duties under the LTIP and execute all other responsibilities permitted or required under the LTIP. In the event that the committee is not comprised of “non-employee directors” within the meaning of Rule 16b-3 under the Exchange Act, the full board of directors or a subcommittee of two or more nonemployee directors will administer all awards granted to individuals that are subject to Section 16 of the Exchange Act.

The maximum aggregate number of common units that may be issued pursuant to any and all awards under the LTIP shall not exceed common units, subject to adjustment due to recapitalization or reorganization, or related to forfeitures or expiration of awards, as provided under the LTIP.

If any common units subject to any award are not issued or transferred, or cease to be issuable or transferable for any reason, including (but not exclusively) because units are withheld or surrendered in payment of taxes or any exercise or purchase price relating to an award or because an award is forfeited, terminated, expires unexercised, is settled in cash in lieu of common units, or is otherwise terminated without a delivery of units, those common units will again be available for issue, transfer, or exercise pursuant to awards under the

Index to Financial Statements

LTIP, to the extent allowable by law. Common units to be delivered pursuant to awards under our LTIP may be common units acquired by our general partner in the open market, from any other person, directly from us, or any combination of the foregoing.

We may grant unit options to eligible persons. Unit options are rights to acquire common units at a specified price. The exercise price of each unit option granted under the LTIP will be stated in the unit option agreement and may vary; provided, however, that, the exercise price for an unit option must not be less than 100% of the fair market value per common unit as of the date of grant of the unit option unless that unit option is intended to otherwise comply with the requirements of Section 409A of the Internal Revenue Code of 1986, as amended (the “Code”). Unit options may be exercised in the manner and at such times as the committee determines for each unit option, unless that unit option is determined to be subject to Section 409A of the Code, in which case the unit option will be subject to any necessary timing restrictions imposed by the Code or federal regulations. The committee will determine the methods and form of payment for the exercise price of a unit option and the methods and forms in which common units will be delivered to a participant.

A unit appreciation right is the right to receive, in cash or in common units, as determined by the committee, an amount equal to the excess of the fair market value of one common unit on the date of exercise over the grant price of the unit appreciation right. The committee will be able to make grants of unit appreciation rights and will determine the time or times at which a unit appreciation right may be exercised in whole or in part. The exercise price of each unit appreciation right granted under the LTIP will be stated in the unit appreciation right agreement and may vary; provided, however, that, the exercise price must not be less than 100% of the fair market value per common unit as of the date of grant of the unit appreciation right, unless that unit appreciation right is intended to otherwise comply with the requirements of Section 409A of the Code.

A restricted unit is a grant of a common unit subject to a risk of forfeiture, performance conditions, restrictions on transferability and any other restrictions imposed by the committee in its discretion. Restrictions may lapse at such times and under such circumstances as determined by the committee. The committee shall provide, in the restricted unit agreement, whether the restricted unit will be forfeited upon certain terminations of employment. Unless otherwise determined by the committee, a common unit distributed in connection with a unit split or unit dividend, and other property distributed as a dividend, will generally be subject to restrictions and a risk of forfeiture to the same extent as the restricted unit with respect to which such common unit or other property has been distributed.

The committee will be authorized to grant common units that are not subject to restrictions. The committee may grant unit awards to any eligible person in such amounts as the committee, in its sole discretion, may select.

Phantom units are rights to receive common units, cash or a combination of both at the end of a specified period. The committee may subject phantom units to restrictions (which may include a risk of forfeiture) to be specified in the phantom unit agreement that may lapse at such times determined by the committee. Phantom units may be satisfied by delivery of common units, cash equal to the fair market value of the specified number

Index to Financial Statements

of common units covered by the phantom unit or any combination thereof determined by the committee. Cash distribution equivalents may be paid during or after the vesting period with respect to a phantom unit, as determined by the committee.

The committee will be able to grant distribution equivalent rights in tandem with awards under the LTIP (other than unit awards or an award of restricted units), or distribution equivalent rights may be granted alone. Distribution equivalent rights entitle the participant to receive cash equal to the amount of any cash distributions made by us during the period the distribution equivalent right is outstanding. Payment of cash distributions pursuant to a distribution equivalent right issued in connection with another award may be subject to the same vesting terms as the award to which it relates or different vesting terms, in the discretion of the committee.

The LTIP will permit the grant of awards denominated in and settled in cash. Cash awards may be based, in whole or in part, on the value or performance of a common unit.

The committee may condition the right to exercise or receive an award under the LTIP, or may increase or decrease the amount payable with respect to an award, based on the attainment of one or more performance conditions deemed appropriate by the committee.

The LTIP will permit the grant of other unit-based awards, which are awards that may be based, in whole or in part, on the value or performance of a common unit or are denominated or payable in common units. Upon settlement, these other unit-based awards may be paid in common units, cash or a combination thereof, as provided in the award agreement.

The LTIP will permit the grant of awards in substitution for similar awards held by individuals who become employees, consultants or directors as a result of a merger, consolidation, or acquisition by or involving us, an affiliate of another entity, or the assets of another entity. Such substitute awards that are unit options or unit appreciation rights may have exercise prices less than 100% of the fair market value per common unit on the date of the substitution if such substitution complies with Section 409A of the Code and its regulations and other applicable laws and exchange rules.

At our discretion, and subject to conditions that the committee may impose, a participant’s tax withholding with respect to an award may be satisfied by withholding from any payment related to an award or by the withholding of common units issuable pursuant to the award based on the fair market value of the common units.

If any “equity restructuring” event occurs that could result in an additional compensation expense under Financial Accounting Standards Board Accounting Standards Codification Topic 718 (“FASB ASC Topic 718”)

Index to Financial Statements

if adjustments to awards with respect to such event were discretionary, the committee will equitably adjust the number and type of units covered by each outstanding award and the terms and conditions of each such award to equitably reflect the restructuring event and the committee will adjust the number and type of units with respect to which future awards may be granted. With respect to a similar event that would not result in a FASB ASC Topic 718 accounting charge if adjustment to awards were discretionary, the committee shall have complete discretion to adjust awards in the manner it deems appropriate. In the event the committee makes any adjustment in accordance with the foregoing provisions, a corresponding and proportionate adjustment shall be made with respect to the maximum number of units available under the LTIP and the kind of units or other securities available for grant under the LTIP. Furthermore, in the case of (i) a subdivision or consolidation of the common units (by reclassification, split or reverse split or otherwise), (ii) a recapitalization, reclassification, or other change in our capital structure or (iii) any other reorganization, merger, combination, exchange, or other relevant change in capitalization of our equity, then a corresponding and proportionate adjustment shall be made in accordance with the terms of the LTIP, as appropriate, with respect to the maximum number of units available under the LTIP, the number of units that may be acquired with respect to an award, and, if applicable, the exercise price of an award, in order to prevent dilution or enlargement of awards as a result of such events.

Upon a “change in control” (as defined in the LTIP), the committee may, in its discretion, (i) remove any forfeiture restrictions applicable to an award, (ii) accelerate the time of exercisability or vesting of an award, (iii) require awards to be surrendered in exchange for a cash payment, (iv) cancel unvested awards without payment or (v) make adjustments to awards as the committee deems appropriate to reflect the change in control.

The consequences of the termination of a participant’s employment, consulting arrangement or membership on the board of directors will be determined by the committee in the terms of the relevant award agreement.

We and our general partner had no material assets or operations prior to the completion of this offering. As such, we have not accrued or paid any obligations with respect to compensation for directors for any periods prior to the completion of this offering.

Going forward, we believe that attracting and retaining qualified non-employee directors of our general partner will be critical to our future value growth and governance. We also believe that a significant portion of the total compensation package for our non-employee directors should be equity-based to align the interest of directors with our unitholders.

We are reviewing the non-employee director compensation packages provided by certain peer companies and intend to implement a non-employee director compensation program in connection with this offering.

The executive officers or employees of our general partner or of Oasis who also serve as directors of our general partner will not receive additional compensation for their service as a director of our general partner.

Each member of the board of directors of our general partner will be indemnified for his actions associated with being a director to the fullest extent permitted under Delaware law.

Index to Financial Statements

The following table sets forth the beneficial ownership of our common and subordinated units that will be issued and outstanding upon the consummation of this offering and the related transactions and held by:

The amounts and percentage of our common units beneficially owned are reported on the basis of regulations of the SEC governing the determination of beneficial ownership of securities. Under the rules of the SEC, a person is deemed to be a “beneficial owner” of a security if that person has or shares “voting power,” which includes the power to vote or to direct the voting of such security, or “investment power,” which includes the power to dispose of or to direct the disposition of such security. Except as indicated by footnote, the persons named in the table below have sole voting and investment power with respect to all common units shown as beneficially owned by them, subject to community property laws where applicable. Unless otherwise noted, the address for each beneficial owner listed below is 1001 Fannin Street, Suite 1500, Houston, Texas 77002.

The following table does not include any common units that officers, directors, employees and certain other persons associated with us purchase in this offering through the directed unit program described under “Underwriting”:

Index to Financial Statements

The following table sets forth the number of shares of common stock of Oasis owned by each of the named executive officers and directors of our general partner and all directors and executive officers of our general partner as a group as of , 2017:

Index to Financial Statements

After this offering, assuming that the underwriters do not exercise their option to purchase additional common units, Oasis will own common units and subordinated units representing an aggregate % limited partner interest in us. Oasis will own and control (and appoint all the directors of) our general partner, which will own a non-economic general partner interest in us and all of the incentive distribution rights.

The terms of the transactions and agreements disclosed in this section were determined by and among affiliated entities and, consequently, are not the result of arm’s length negotiations. These terms are not necessarily at least as favorable to the parties to these transactions and agreements as the terms that could have been obtained from unaffiliated third parties.

The following table summarizes the distributions and payments to be made by us to our general partner and its affiliates in connection with the formation, ongoing operation and any liquidation of us:

Index to Financial Statements

In connection with this offering, we will enter into certain agreements with Oasis, as described in more detail below.

In connection with this offering, we will enter into a registration rights agreement with Oasis pursuant to which we may be required to register the sale of the (i) common units issued (or issuable) to Oasis pursuant to the contribution agreement, (ii) subordinated units and (iii) common units issuable upon conversion of

Index to Financial Statements

subordinated units pursuant to the terms of the partnership agreement (together, the “Registrable Securities”) it holds. Under the registration rights agreement, Oasis will have the right to request that we register the sale of Registrable Securities held by it, and Oasis will have the right to require us to make available shelf registration statements permitting sales of Registrable Securities into the market from time to time over an extended period, subject to certain limitations. Pursuant to the registration rights agreement and our partnership agreement, we may be required to undertake a future public or private offering and use the proceeds (net of underwriting or placement agency discounts, fees and commissions, as applicable) to redeem an equal number of common units from them. In addition, the registration rights agreement gives Oasis “piggyback” registration rights under certain circumstances. The registration rights agreement also includes provisions dealing with indemnification and contribution and allocation of expenses. All of the Registrable Securities held by Oasis and any permitted transferee will be entitled to these registration rights.

In connection with the closing of this offering, we will enter into an omnibus agreement with our general partner, OMS and Oasis, pursuant to which:

Oasis may terminate the omnibus agreement in the event that it ceases to be our affiliate and may also terminate the omnibus agreement if we fail to pay amounts due under that agreement in accordance with its terms. The omnibus agreement may only be assigned by either party with the other party’s consent.

In connection with the closing of this offering, we intend to enter into a contribution agreement with OMS following certain other formation transactions described under “Summary—Formation Steps and Partnership Structure,” that will affect the transfer of a 100% interest in Bighorn DevCo, a 10% interest in Bobcat DevCo and a 35% interest in Beartooth DevCo to us, and the issuance of common units, subordinated units and the net proceeds of this offering by us to OMS and the issuance of incentive distribution rights by us to our general partner. All of the transaction expenses incurred in connection with these transactions will be paid from proceeds of this offering.

Index to Financial Statements

In connection with the completion of this offering, we will enter into a 15-year services and secondment agreement with Oasis, pursuant to which we will operate our midstream infrastructure, and Oasis will provide all personnel, equipment, electricity, chemicals, and services (including third-party services) required for us to operate such assets. We will reimburse Oasis for our share of the actual costs of operating such assets. We expect our operating costs will consist of the cost of equipment rental, labor, workovers and power, among other general operating costs. Pursuant to the services and secondment agreement, Oasis will, or will cause its affiliates to, perform centralized corporate, general and administrative services for us, such as legal, corporate recordkeeping, planning, budgeting, regulatory, accounting, billing, business development, treasury, insurance administration and claims processing, risk management, health, safety and environmental, information technology, human resources, investor relations, cash management and banking, payroll, internal audit, taxes and engineering. Our services and secondment agreement requires us to reimburse Oasis for direct general and administrative expenses incurred by Oasis for the provision of the above services. Additionally, we will reimburse Oasis for a portion of the compensation expense paid to employees of Oasis that spend time managing and operating our business. The expenses of executive officers and non-executive employees will be allocated to us based on the amount of time spent managing our business and operations. The reimbursements to our general partner and Oasis will be made prior to cash distributions to our common unitholders. We anticipate reimbursement to Oasis and its affiliates will vary with the size and scale of our operations, among other factors.

For a description of the commercial agreements we will enter into with OMS and other wholly owned subsidiaries of Oasis see “Business—Contractual Arrangements with Oasis.”

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

We expect that the board of directors of our general partner will adopt policies for the review, approval and ratification of transactions with related persons. We anticipate the board will adopt a written code of business conduct and ethics, under which a director would be required to bring to the attention of our chief executive officer or the board any conflict or potential conflict of interest that may arise between the director or any affiliate of the director, on the one hand, and us or our general partner on the other. The resolution of any such conflict or potential conflict should, at the discretion of the board in light of the circumstances, be determined by a majority of the disinterested directors. In determining whether to approve or ratify a transaction with a related party, we expect that the board of directors of our general partner will take into account, among other factors it deems appropriate, (1) whether the transaction is on terms no less favorable than terms generally available to an unaffiliated third party under the same or similar circumstances, (2) the extent of the related person’s interest in the transaction and (3) whether the interested transaction is material to the Partnership. As described in “Conflicts of Interest and Fiduciary Duties,” our partnership agreement contains detailed provisions regarding the resolution of conflicts of interest, as well as the standard of care the board of directors of our general partner must satisfy in doing so.

If a conflict or potential conflict of interest arises between our general partner or its affiliates, on the one hand, and us or our unitholders, on the other hand, the resolution of any such conflict or potential conflict should be addressed by the board of directors of our general partner in accordance with the provisions of our partnership agreement. Such a conflict of interest may arise, for example, in connection with negotiating and approving the acquisition of any assets from our sponsor, including in connection with our ROFO under the omnibus agreement. At the discretion of the board in light of the circumstances, the resolution may be determined by the board in its entirety or by a conflicts committee meeting the definitional requirements for such a committee under our partnership agreement. We do not expect that our code of business conduct and ethics or any policies that the board of directors of our general partner will adopt will require the approval of any transactions with related persons, including our sponsor, by our unitholders.

Index to Financial Statements

As described elsewhere in this prospectus, we expect to have the opportunity to acquire additional assets from our sponsor in the future, including in connection with our ROFO provided in the omnibus agreement. Our sponsor or other affiliates of our general partner are free to offer properties to us on terms they deem acceptable. We expect that, under our code of business conduct and ethics, the board of directors of our general partner (or the conflicts committee, if the board of directors delegates the necessary authority to the conflicts committee) will be free to accept or reject any such offers and to negotiate any terms it deems acceptable to us and that the board of directors of our general partner or the conflicts committee will decide the appropriate value of any assets offered to us by affiliates of our general partner. In making such determination of value, the board of directors of our general partner or the conflicts committee will be permitted to consider any factors they determine in good faith to consider. We expect the board of directors or the conflicts committee will consider a number of economic, operational and market factors in its determination of value.

Upon our adoption of our code of business conduct and ethics, we would expect that any executive officer will be required to avoid conflicts of interest unless approved by the board of directors of our general partner. The code of business conduct and ethics will be adopted in connection with the closing of this offering, and as a result, the transactions described above were not reviewed according to such procedures.

Please read “Conflicts of Interest and Fiduciary Duties—Conflicts of Interest” for additional information regarding the relevant provisions of our partnership agreement.

Index to Financial Statements

Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its directors, officers, affiliates (including Oasis) and owners, on the one hand, and us and our limited partners, on the other hand. Conflicts may arise as a result of the duties of our general partner and its directors and officers to act for the benefit of its owners, which may conflict with our interests and the interests of our public unitholders. We are managed and operated by the board of directors and officers of our general partner, OMP GP, which is owned by Oasis. All of our initial officers and a majority of our initial directors will also be officers or directors of Oasis. Although our general partner has a contractual duty to manage us in a manner that it believes is not adverse to our interests, the directors and officers of our general partner have a fiduciary duty at the same time to manage our general partner in a manner that is beneficial to Oasis. In addition, our directors and officers who are also directors and officers of Oasis have a fiduciary duty to manage Oasis in a manner that is beneficial to Oasis and its shareholders. The Delaware Act provides that Delaware limited partnerships may, in their partnership agreements, expand, restrict or eliminate the fiduciary duties otherwise owed by the general partner to the limited partners and the partnership. Pursuant to this authority, our partnership agreement contains various provisions replacing the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing the duties of the general partner and the methods of resolving conflicts of interest. Furthermore, our partnership agreement specifically defines the remedies available to unitholders for actions taken that, without these defined liability standards, might constitute breaches of fiduciary duty under applicable Delaware law.

Whenever a conflict arises between our general partner or its owners and affiliates (including Oasis), on the one hand, and us or our limited partners, on the other hand, the resolution or course of action in respect of such conflict of interest shall be permitted and deemed approved by us and all our limited partners and shall not constitute a breach of our partnership agreement, of any agreement contemplated thereby or of any duty, if the resolution or course of action in respect of such conflict of interest is:

However, our general partner may, but is not required to, seek such approval. If our general partner does not seek approval from the conflicts committee or from holders of common units as described above and the board of directors of our general partner approves the 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 of our general partner acted in good faith, and in any proceeding brought by or on behalf of us or any of our unitholders, 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. Unless the resolution of a conflict is specifically provided for in our partnership agreement, the board of directors of our general partner or the conflicts committee of the board of directors of our general partner may consider any factors they determine in good faith to consider when resolving a conflict. An independent third party is not required to evaluate the resolution. Under our partnership agreement, a determination, other action or failure to act by our general partner, the board of directors of our general partner or any committee thereof (including the conflicts committee) will be deemed to be “in good faith” unless our general partner, the board of directors of our general partner or any committee thereof (including the conflicts committee) believed such determination, other action or failure to act was adverse to the interest of the partnership. Please read “Management—Committees of the Board of Directors—Conflicts Committee” for information about the conflicts committee of our general partner’s board of directors.

Index to Financial Statements

Conflicts of interest could arise in the situations described below, among others:

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 amount of distributable cash is affected by decisions of our general partner regarding such matters as:

In addition, borrowings by us and our affiliates do not constitute a breach of any duty owed by our general partner to our unitholders, including borrowings that have the purpose or effect of:

In addition, our general partner may use an amount, initially equal to $ million, which would not otherwise constitute operating surplus, in order to permit the payment of distributions on subordinated units and the incentive distribution rights. All of these actions may affect the amount of cash distributed to our unitholders and our general partner and may facilitate the conversion of subordinated units into common units. Please read “How We Make Distributions To Our Partners.”

For example, in the event we have not generated sufficient cash from our operations to pay the minimum quarterly distribution on our common units and our subordinated units, our partnership agreement permits us to borrow funds, which would enable us to make such distribution on all outstanding units. Please read “How We Make Distributions To Our Partners—Operating Surplus and Capital Surplus—Operating Surplus.”

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

The officers and certain directors of our general partner that are also officers and/or directors of Oasis have fiduciary duties to Oasis that may cause them to pursue business strategies that disproportionately benefit Oasis or which otherwise are not in our best 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.

Our partnership agreement contains provisions that replace the 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. 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 any limited partner. Examples include the exercise of its call right, its voting rights with respect to any units it owns, its registration rights and its determination whether or not to consent to any merger or consolidation or amendment of the partnership agreement.

Index to Financial Statements

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.

In addition to the provisions described above, our partnership agreement contains provisions that restrict the remedies available to our unitholders for actions that might otherwise constitute breaches of fiduciary duty. For example, our partnership agreement provides that:

By purchasing a common unit, a common unitholder will agree to become bound by the provisions in our partnership agreement, including the provisions discussed above. Please read “—Fiduciary Duties of Our General Partner.”

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

Any agreements between us, on the one hand, and our general partner and its affiliates, on the other, will not grant to the unitholders, separate and apart from us, the right to enforce the obligations of our general partner and its affiliates in our favor.

Contracts between us, on the one hand, and our general partner and its affiliates (including Oasis), on the other, are not and will not be the result of arm’s-length negotiations.

Neither our partnership agreement nor any of the other agreements, contracts and arrangements between us and our general partner and its affiliates are or will be the result of arm’s-length negotiations. 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. Oasis may have 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. Even though Oasis controls our general partner, our general partner will determine, in good faith, the terms of any of such future transactions.

Index to Financial Statements

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

Under our partnership agreement, our general partner has full power and authority to do all things, other than those items that require unitholder approval, necessary or appropriate to conduct our business including, but not limited to, the following actions:

Please read “The Partnership Agreement” for information regarding the voting rights of unitholders.

Index to Financial Statements

We may choose not to retain separate counsel for ourselves or for the holders of common units.

The attorneys, independent accountants and others who perform services for us have been retained by our general partner. Attorneys, independent accountants and others who perform services for us are selected by our general partner or the conflicts committee of the board of directors of our general partner and may perform services for our general partner and its affiliates. We may retain separate counsel for ourselves or the conflict committee in the event of a conflict of interest between our general partner and its affiliates, on the one hand, and us or the holders of common units, on the other, depending on the nature of the conflict, although we may choose not to do so.

Our general partner’s affiliates may compete with us, and neither our general partner nor its affiliates have any obligation to present business opportunities to us.

Our partnership agreement provides that our general partner is restricted from engaging in any business other than those activities incidental to its management or ownership of debt or equity interests in us or our subsidiaries or providing management or other services to other persons.

However, affiliates of our general partner are not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us, and such affiliates (including Oasis) may acquire, construct or dispose of assets in the future without any obligation to offer us the opportunity to acquire those assets. In addition, under our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, will not apply to our general partner and its affiliates. As a result, neither our general partner nor any of its affiliates have any obligation to present business opportunities to us.

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. This election may result in lower distributions to our common unitholders in certain situations.

The holder or holders of a majority of our incentive distribution rights (initially our general partner) have the right, at any time when there are no subordinated units outstanding and they have received incentive distributions at the highest level to which they are entitled (50%) for each of the prior four consecutive fiscal quarters, to reset the initial target distribution levels at higher levels based on our cash distribution levels at the time of the exercise of the reset election. Following a reset election, a baseline distribution amount will be calculated equal to an amount equal to the prior cash distribution per common unit for the fiscal quarter immediately preceding the reset election (such amount is referred to as 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.

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 unit without such conversion. However, our general partner may transfer the incentive distribution rights at any time. It is possible that our general partner or a transferee could exercise this reset election at a time when we are experiencing declines in our aggregate cash distributions or at a time when the holders of the incentive distribution rights expect that we will experience declines in our aggregate cash distributions in the foreseeable future. In such situations, the holders of the incentive distribution rights may be experiencing, or may expect to experience, declines in the cash distributions it receives related to the incentive distribution rights and may therefore desire to be issued our common units, which are entitled to specified priorities with respect to our distributions and which therefore may be more advantageous for them to own in lieu of the right to receive incentive distribution payments based on target distribution levels that are less certain to be achieved. As a result, a reset election may cause our common unitholders to experience dilution in the amount of cash distributions that they would have otherwise received had we not issued new common units to the holders of the incentive distribution rights in connection with resetting the target distribution levels. Please read “How We Make Distributions To Our Partners—Incentive Distribution Rights.”

Index to Financial Statements

Duties owed to unitholders by our general partner are prescribed by law and in our partnership agreement. The Delaware Act provides that Delaware limited partnerships may, in their partnership agreements, expand, restrict or eliminate the fiduciary duties otherwise owed by the general partner to limited partners and the partnership.

Our partnership agreement contains various provisions that eliminate and replace the fiduciary duties that might otherwise be owed by our general partner. We have adopted these provisions to allow our general partner or its affiliates to engage in transactions with us that otherwise might be prohibited by state law fiduciary standards and to take into account the interests of other parties in addition to our interests when resolving conflicts of interest. We believe this is appropriate and necessary because the board of directors of our general partner has a duty to manage our partnership in good faith and a duty to manage our general partner in a manner beneficial to its owner. Without these modifications, our general partner’s ability to make decisions involving conflicts of interest would be restricted. Replacing the fiduciary duty standards in this manner benefits our general partner by enabling it to take into consideration all parties involved in the proposed action. Replacing the fiduciary duty standards also strengthens the ability of our general partner to attract and retain experienced and capable directors. Replacing the fiduciary duty standards represents a detriment to our public unitholders because it restricts the remedies available to our public unitholders for actions that, without those limitations, might constitute breaches of fiduciary duty, as described below, and permits our general partner to take into account the interests of third parties in addition to our interests when resolving a conflict of interest.

The following is a summary of the fiduciary duties imposed on general partners of a limited partnership by the Delaware Act in the absence of partnership agreement provisions to the contrary, the contractual duties of our general partner contained in our partnership agreement that replace the fiduciary duties that would otherwise be imposed by Delaware law on our general partner and the rights and remedies of our unitholders with respect to these contractual duties:

Index to Financial Statements

By purchasing our common units, each common unitholder automatically agrees to be bound by the provisions in our partnership agreement, including the provisions discussed above. This is in accordance with the policy of the Delaware Act favoring the principle of freedom of contract and the enforceability of partnership agreements. The failure of a limited partner to sign our partnership agreement does not render the partnership agreement unenforceable against that person.

Under our partnership agreement, we must indemnify our general partner and its officers, directors, managers and certain other specified persons, to the fullest extent permitted by law, against liabilities, costs and expenses incurred by our general partner or these other persons. We must provide this indemnification unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that such losses or liabilities were the result of the conduct of our general partner or such officer or director engaged in by it in bad faith or, with respect to any criminal conduct, with the knowledge that its conduct was unlawful. Thus, our general partner could be indemnified for its negligent acts if it meets the requirements set forth above. To the extent these provisions purport to include indemnification for liabilities arising under the Securities Act, in the opinion of the SEC, such indemnification is contrary to public policy and, therefore, unenforceable. Please read “The Partnership Agreement—Indemnification.”

Index to Financial Statements

The common units and the subordinated units are separate classes of limited partner interests in us. Unitholders are entitled to participate in partnership distributions and exercise the rights or privileges available to limited partners under our partnership agreement. For a description of the relative rights and preferences of unitholders in and to partnership distributions, please read this section and “How We Make Distributions To Our Partners.” For a description of other rights and privileges of limited partners under our partnership agreement, including voting rights, please read “The Partnership Agreement.”

Computershare Trust Company, N.A. will serve as the registrar and transfer agent for the common units. We will pay all fees charged by the transfer agent for transfers of common units except the following, which must be paid by our common unitholders:

There will be no charge to our unitholders for disbursements of our cash distributions. We will indemnify the transfer agent, its agents and each of their stockholders, directors, officers and employees against all claims and losses that may arise out of acts performed or omitted for its activities in that capacity, except for any liability due to any gross negligence or intentional misconduct of the indemnified person or entity.

The transfer agent may resign, by notice to us, or be removed by us. The resignation or removal of the transfer agent will become effective upon our appointment of a successor transfer agent and registrar and its acceptance of the appointment. If no successor is appointed or has not accepted its appointment within 30 days of the resignation or removal, our general partner may act as the transfer agent and registrar until a successor is appointed.

Upon the transfer of a common unit in accordance with our partnership agreement, the transferee of the common unit shall be admitted as a limited partner with respect to the common units transferred when such transfer and admission are reflected in our books and records. Each transferee:

Our general partner will cause any transfers to be recorded on our books and records no less frequently than quarterly.

Index to Financial Statements

We may, at our discretion, treat the nominee holder of a common unit as the absolute owner. In that case, the beneficial holder’s rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.

Common units are securities and any transfers are subject to the laws governing the transfer of securities. In addition to other rights acquired upon transfer, the transferor gives the transferee the right to become a substituted limited partner in our partnership for the transferred common units.

Until a common unit has been transferred on our books, we and the transfer agent may treat the record holder of the common unit as the absolute owner for all purposes, except as otherwise required by law or stock exchange regulations.

Index to Financial Statements

The following is a summary of the material provisions of our partnership agreement, which we will adopt in connection with the closing of this offering. The form of our partnership agreement is included in this prospectus as Appendix A. We will provide investors and prospective investors with a copy of our partnership agreement, when available, upon request at no charge.

We summarize the following provisions of our partnership agreement elsewhere in this prospectus:

We were organized in June 2014 as a Delaware limited partnership and will have a perpetual existence unless terminated pursuant to the terms of our partnership agreement.

Our purpose, as set forth in our partnership agreement, is limited to any business activity that is approved by our general partner and that lawfully may be conducted by a limited partnership organized under Delaware law.

Although our general partner has the ability to cause us and our subsidiaries to engage in activities other than the midstream business, our general partner may decline to do so in its sole discretion and free of any duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interests of us or the limited partners. Our general partner is generally authorized to perform all acts it determines to be necessary or appropriate to carry out our purposes and to conduct our business.

Our partnership agreement 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. 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 partnership agreement specifies the manner in which we will make cash distributions to holders of our common units and other partnership securities as well as to our general partner in respect of its incentive distribution rights. For a description of these cash distribution provisions, please read “How We Make Distributions To Our Partners.”

Unitholders are not obligated to make additional capital contributions, except as described below under “—Limited Liability.”

Index to Financial Statements

The following is a summary of the unitholder vote required for approval of the matters specified below. Matters that require the approval of a “unit majority” require:

In voting their common and subordinated units, our general partner and its affiliates will have no duty or obligation whatsoever to us or the limited partners, including any duty to act in the best interests of us or the limited partners.

The incentive distribution rights may be entitled to vote in certain circumstances.

Index to Financial Statements

If any person or group other than our general partner and its affiliates acquires beneficial ownership of 20% or more of any class of units, that person or group loses voting rights on all of its units. This loss of voting rights does not apply to Oasis or to any person or group that acquires the units from our general partner or its affiliates and any transferees of that person or group approved by our general partner or to any person or group who acquires the units with the specific prior approval of our general partner.

Our partnership agreement is governed by Delaware law. Our partnership agreement requires that any claims, suits, actions or proceedings:

shall be exclusively brought in the Court of Chancery of the State of Delaware (or, if such court does not have subject matter jurisdiction thereof, any other court located in the State of Delaware with subject matter jurisdiction), regardless of whether such claims, suits, actions or proceedings sound in contract, tort, fraud or otherwise, are based on common law, statutory, equitable, legal or other grounds, or are derivative or direct claims. By purchasing a common unit, a limited partner is irrevocably consenting to these limitations and provisions regarding claims, suits, actions or proceedings and submitting to the exclusive jurisdiction of the Court of Chancery of the State of Delaware (or such other court) in connection with any such claims, suits, actions or proceedings.

Our partnership agreement provides that if limited partners or any persons holding a beneficial interest in us file a claim, suit, action or proceeding against us of a type identified in the bullet points under the above heading “—Applicable Law; Forum, Venue and Jurisdiction” and do not obtain a judgment on the merits that substantially achieves, in substance and amount, the full remedy sought in any such claim, suit, action or proceeding, then such partners or persons will be jointly and severally obligated to reimburse us and our affiliates, including our general partner, the owners of our general partner and any officer or director of our general partner, 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. Our partnership agreement does not define what constitutes a judgment that “substantially achieves, in substance and amount, the full remedy sought,” though we intend to apply a broad interpretation to such provision in order to apply the fee-shifting provision broadly. However, there is no precise established definition of the phrase under applicable law. As a result, whether a specific judgment satisfies the foregoing criteria will be subject to judicial interpretation. By purchasing a common unit, a limited partner is irrevocably consenting to these reimbursement obligations as set forth in our partnership agreement.

Index to Financial Statements

Assuming that a limited partner does not participate in the control of our business within the meaning of the Delaware Act and that he otherwise acts in conformity with the provisions of the partnership agreement, his liability under the Delaware Act will be limited, subject to possible exceptions, to the amount of capital he is obligated to contribute to us for his common units plus his share of any undistributed profits and assets. However, if it were determined that the right, or exercise of the right, by the limited partners as a group:

constituted “participation in the control” of our business for the purposes of the Delaware Act, then the limited partners could be held personally liable for our obligations under the laws of Delaware, to the same extent as our general partner. This liability would extend to persons who transact business with us under the reasonable belief that the limited partner is a general partner. Neither our partnership agreement nor the Delaware Act specifically provides for legal recourse against our general partner if a limited partner were to lose limited liability through any fault of our general partner. While this does not mean that a limited partner could not seek legal recourse, we know of no precedent for this type of a claim in Delaware case law.

Under the Delaware Act, a limited partnership may not make a distribution to a partner if, after the distribution, all liabilities of the limited partnership, other than liabilities to partners on account of their partnership interests and liabilities for which the recourse of creditors is limited to specific property of the partnership, would exceed the fair value of the assets of the limited partnership, except that the fair value of property that is subject to a liability for which the recourse of creditors is limited is included in the assets of the limited partnership only to the extent that the fair value of that property exceeds that liability. For the purpose of determining the fair value of the assets of a limited partnership, the Delaware Act provides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the limited partnership only to the extent that the fair value of that property exceeds the nonrecourse liability. The Delaware Act provides that a limited partner who receives a distribution and knew at the time of the distribution that the distribution was in violation of the Delaware Act shall be liable to the limited partnership for the amount of the distribution for three years.

Following the completion of this offering, we expect that our subsidiaries will conduct business in several states and we may have subsidiaries that conduct business in other states or countries in the future. Maintenance of our limited liability as owner of our operating subsidiaries may require compliance with legal requirements in the jurisdictions in which the operating subsidiaries conduct business, including qualifying our subsidiaries to do business there.

Limitations on the liability of members or limited partners for the obligations of a limited liability company or limited partnership have not been clearly established in many jurisdictions. If, by virtue of our ownership interest in our subsidiaries or otherwise, it were determined that we were conducting business in any jurisdiction without compliance with the applicable limited partnership or limited liability company statute, or that the right or exercise of the right by the limited partners as a group to remove or replace our general partner, to approve some amendments to our partnership agreement, or to take other action under our partnership agreement constituted “participation in the control” of our business for purposes of the statutes of any relevant jurisdiction, then the limited partners could be held personally liable for our obligations under the law of that jurisdiction to the same extent as our general partner under the circumstances. We will operate in a manner that our general partner considers reasonable and necessary or appropriate to preserve the limited liability of the limited partners.

Index to Financial Statements

Our partnership agreement authorizes us to issue an unlimited number of additional partnership interests for the consideration and on the terms and conditions determined by our general partner without the approval of the unitholders.

It is possible that we will fund acquisitions through the issuance of additional common units, subordinated units or other partnership interests. Holders of any additional common units we issue will be entitled to share equally with the then-existing common unitholders in our distributions. In addition, the issuance of additional common units or other partnership interests may dilute the value of the interests of the then-existing common unitholders in our net assets.

In accordance with Delaware law and the provisions of our partnership agreement, we may also issue additional partnership interests that, as determined by our general partner, may have rights to distributions or special voting rights to which the common units are not entitled. In addition, our partnership agreement does not prohibit our subsidiaries from issuing equity interests, which may effectively rank senior to the common units.

Our general partner will have the right, which it may from time to time assign in whole or in part to any of its affiliates, to purchase common units, subordinated units or other partnership interests whenever, and on the same terms that, we issue partnership interests to persons other than our general partner and its affiliates, to the extent necessary to maintain the percentage interest of our general partner and its affiliates, including such interest represented by common and subordinated units, that existed immediately prior to each issuance. The common unitholders will not have preemptive rights under our partnership agreement to acquire additional common units or other partnership interests.

Amendments to our partnership agreement may be proposed only by our general partner. However, our general partner will have no duty or obligation to propose any amendment and may decline to do so free of any duty or obligation whatsoever to us or the limited partners, including any duty to act in the best interests of us or the limited partners. In order to adopt a proposed amendment, other than the amendments discussed below, our general partner is required to seek written approval of the holders of the number of units required to approve the amendment or to call a meeting of the limited partners to consider and vote upon the proposed amendment. Except as described below, an amendment must be approved by a unit majority.

The provision of our partnership agreement preventing the amendments having the effects described in the clauses above can be amended upon the approval of the holders of at least 90% of the outstanding units, voting as a single class (including units owned by our general partner and its affiliates). Upon completion of the offering, an affiliate of our general partner will own approximately % 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).

Index to Financial Statements

Our general partner may generally make amendments to our partnership agreement without the approval of any limited partner to reflect:

In addition, our general partner may make amendments to our partnership agreement, without the approval of any limited partner, if our general partner determines that those amendments:

Index to Financial Statements

Any amendment that our general partner determines adversely affects in any material respect one or more particular classes of limited partners, and is not permitted to be adopted by our general partner without limited partner approval, will require the approval of at least a majority of the class or classes so affected, but no vote will be required by any class or classes of limited partners that our general partner determines are not adversely affected in any material respect. Any such amendment that would have a material adverse effect on the rights or preferences of any type or class of outstanding units in relation to other classes of units will require the approval of at least a majority of the type or class of units so affected. Any such amendment that would reduce the voting percentage required to take any action other than to remove the general partner or call a meeting of unitholders is required to be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute not less than the voting requirement sought to be reduced. Any such amendment that would increase the percentage of units required to remove the general partner or call a meeting of unitholders must be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute not less than the percentage sought to be increased. For amendments of the type not requiring unitholder approval, our general partner will not be required to obtain an opinion of counsel that an amendment will neither result in a loss of limited liability to the limited partners nor result in our being treated as a taxable entity for federal income tax purposes in connection with any of the amendments. No other amendments to our partnership agreement will become effective without the approval of holders of at least 90% of the outstanding units, voting as a single class, unless we first obtain an opinion of counsel to the effect that the amendment will not affect the limited liability under applicable law of any of our limited partners.

A merger, consolidation or conversion of us requires the prior consent of our general partner. However, our general partner will have no duty or obligation to consent to any merger, consolidation or conversion and may decline to do so free of any duty or obligation whatsoever to us or the limited partners, including any duty to act in the best interest of us or the limited partners.

In addition, our partnership agreement generally prohibits our general partner, without the prior approval of the holders of a unit majority, from causing us to sell, exchange or otherwise dispose of all or substantially all of our assets in a single transaction or a series of related transactions, including by way of merger, consolidation or other combination. Our general partner may, however, mortgage, pledge, hypothecate or grant a security interest in all or substantially all of our assets without such approval. Our general partner may also sell all or substantially all of our assets under a foreclosure or other realization upon those encumbrances without such approval. Finally, our general partner may consummate any merger without the prior approval of our unitholders if we are the surviving entity in the transaction, our general partner has received an opinion of counsel regarding limited liability and tax matters, the transaction would not result in a material amendment to the partnership agreement (other than an amendment that the general partner could adopt without the consent of other partners), each of our units will be an identical unit of our partnership following the transaction and the partnership interests to be issued do not exceed 20% of our outstanding partnership interests (other than incentive distribution rights) immediately prior to the transaction.

If the conditions specified in our partnership agreement are satisfied, our general partner may convert us or any of our subsidiaries into a new limited liability entity or merge us or any of our subsidiaries into, or convey all of our assets to, a newly formed entity, if the sole purpose of that conversion, merger or conveyance is to effect a mere change in our legal form into another limited liability entity, our general partner has received an opinion of counsel regarding limited liability and tax matters and the governing instruments of the new entity provide the limited partners and our general partner with the same rights and obligations as contained in our partnership agreement. Our unitholders are not entitled to dissenters’ rights of appraisal under our partnership agreement or applicable Delaware law in the event of a conversion, merger or consolidation, a sale of substantially all of our assets or any other similar transaction or event.

Index to Financial Statements

We will continue as a limited partnership until dissolved under our partnership agreement. We will dissolve upon:

Upon a dissolution under the last clause above, the holders of a unit majority may also elect, within specific time limitations, to continue our business on the same terms and conditions described in our partnership agreement by appointing as a successor general partner an entity approved by the holders of units representing a unit majority, subject to our receipt of an opinion of counsel to the effect that:

Upon our dissolution, unless our business is continued, the liquidator authorized to wind up our affairs will, acting with all of the powers of our general partner that are necessary or appropriate, liquidate our assets and apply the proceeds of the liquidation as described in “How We Make Distributions To Our Partners—Distributions of Cash Upon Liquidation.” The liquidator may defer liquidation or distribution of our assets for a reasonable period of time or distribute assets to partners in kind if it determines that a sale would be impractical or would cause undue loss to our partners.

Our general partner may withdraw as general partner in compliance with our partnership agreement after giving 90 days’ written notice to our unitholders.

Upon withdrawal of our general partner under any circumstances, other than as a result of a transfer by our general partner of all or a part of its general partner interest in us, the holders of a unit majority may select a successor to that withdrawing general partner. If a successor is not elected, or is elected but an opinion of counsel regarding limited liability and tax matters cannot be obtained, we will be dissolved, wound up and liquidated, unless within a specified period after that withdrawal the holders of a unit majority agree in writing to continue our business and to appoint a successor general partner. Please read “—Dissolution.”

Our general partner may not be removed unless that removal is for cause and is approved by the vote of the holders of not less than 66²/₃% of the outstanding units, voting together as a single class, including units held by our general partner and its affiliates, and we receive an opinion of counsel regarding limited liability and tax matters. Any removal of our general partner is also subject to the approval of a successor general partner by the

Index to Financial Statements

vote of the holders of a majority of the outstanding common units, voting as a class, and the outstanding subordinated units, voting as a class. The ownership of more than 33¹/₃% of the outstanding units by our general partner and its affiliates gives them the ability to prevent our general partner’s removal. At the closing of this offering, an affiliate of our general partner will own approximately % of our outstanding limited partner units, including 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).

In the event of the removal of our general partner or withdrawal of our general partner where that withdrawal violates our partnership agreement, a successor general partner will have the option to purchase the general partner interest and incentive distribution rights of the departing general partner and its affiliates for a cash payment equal to the fair market value of those interests. Under all other circumstances where our general partner withdraws, the departing general partner will have the option to require the successor general partner to purchase the general partner interest and the incentive distribution rights of the departing general partner and its affiliates for fair market value. In each case, this fair market value will be determined by agreement between the departing general partner and the successor general partner. If no agreement is reached, an independent investment banking firm or other independent expert selected by the departing general partner and the successor general partner will determine the fair market value. Or, if the departing general partner and the successor general partner cannot agree upon an expert, then an expert chosen by agreement of the experts selected by each of them will determine the fair market value.

If the option described above is not exercised by either the departing general partner or the successor general partner, the departing general partner’s general partner interest and all its and its affiliates’ incentive distribution rights will automatically convert into common units equal to the fair market value of those interests as determined by an investment banking firm or other independent expert selected in the manner described in the preceding paragraph.

In addition, we will be required to reimburse the departing general partner for all amounts due the departing general partner, including, without limitation, all employee-related liabilities, including severance liabilities, incurred as a result of the termination of any employees employed for our benefit by the departing general partner or its affiliates.

At any time, our general partner may transfer all or any of its general partner interest to another person without the approval of our common unitholders. As a condition of this transfer, the transferee must, among other things, assume the rights and duties of our general partner, agree to be bound by the provisions of our partnership agreement and furnish an opinion of counsel regarding limited liability and tax matters.

At any time, the owner of our general partner may sell or transfer all or part of its ownership interests in our general partner to an affiliate or third party without the approval of our unitholders.

By transfer of subordinated units or incentive distribution rights in accordance with our partnership agreement, each transferee of subordinated units or incentive distribution rights will be admitted as a limited partner with respect to the subordinated units or incentive distribution rights transferred when such transfer and admission is reflected in our books and records. Each transferee:

Index to Financial Statements

Our general partner will cause any transfers to be recorded on our books and records no less frequently than quarterly.

We may, at our discretion, treat the nominee holder of subordinated units or incentive distribution rights as the absolute owner. In that case, the beneficial holder’s rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.

Subordinated units and incentive distribution rights are securities and any transfers are subject to the laws governing transfer of securities. In addition to other rights acquired upon transfer, the transferor gives the transferee the right to become a limited partner for the transferred subordinated units or incentive distribution rights.

Until a subordinated unit or incentive distribution right has been transferred on our books, we and the transfer agent may treat the record holder of the unit or right as the absolute owner for all purposes, except as otherwise required by law or stock exchange regulations.

Our partnership agreement contains specific provisions that are intended to discourage a person or group from attempting to remove OMP GP as our general partner or from otherwise changing our management. Please read “—Withdrawal or Removal of Our General Partner” for a discussion of certain consequences of the removal of our general partner. If any person or group, other than our general partner and its affiliates, acquires beneficial ownership of 20% or more of any class of units, that person or group loses voting rights on all of its units. This loss of voting rights does not apply to any person or group that acquires the units from our general partner or its affiliates or any transferees of that person or group who are notified by our general partner that they will not lose their voting rights or to any person or group who acquires the units with the prior approval of the board of directors of our general partner. Please read “—Meetings; Voting.”

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) we 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 our 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 us (“parent corporation”), then our general partner may, without unitholder approval, cause us 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 our election or conversion 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 of our sponsor. In addition, if our general partner causes partnership interests in us to be held by a parent corporation, our sponsor may choose to retain its partnership interests in us rather than convert their partnership interests into parent corporation shares and our general partner may permit other holders to retain their partnership interests in us on a case by case basis. However, our general partner will have no duty or

Index to Financial Statements

obligation to make any such determination or take any such steps and may decline to do so free of any duty or obligation whatsoever to us or our limited partners, including any duty to act in the best interests of us or our limited partners.

If at any time our general partner and its affiliates (including Oasis) own more than 80% of the then-issued and outstanding limited partner interests of any class, our general partner will have the right, which it may assign in whole or in part to any of its affiliates or to us, to acquire all, but not less than all, of the limited partner interests of the class held by unaffiliated persons, as of a record date to be selected by our general partner, on at least 10, but not more than 60, days’ notice.

As a result of our general partner’s right to purchase outstanding limited partner interests, a holder of limited partner interests may have his limited partner interests purchased at an undesirable time or at a price that may be lower than market prices at various times prior to such purchase or lower than a unitholder may anticipate the market price to be in the future. The tax consequences to a unitholder of the exercise of this call right are the same as a sale by that unitholder of his common units in the market. Please read “Material U.S. Federal Income Tax Consequences—Disposition of Common Units.”

To avoid any adverse effect on the maximum applicable rates chargeable to customers by us or any of our future subsidiaries, or in order to reverse an adverse determination that has occurred regarding such maximum rate, our partnership agreement provides our general partner the power to amend our partnership agreement. If our general partner, with the advice of counsel, determines that our not being treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes, coupled with the tax status (or lack of proof thereof) of one or more of our limited partners (or their owners, to the extent relevant), has, or is reasonably likely to have, a material adverse effect on the maximum applicable rates chargeable to customers by us or our subsidiaries, then our general partner may adopt such amendments to our partnership agreement as it determines necessary or advisable to:

Index to Financial Statements

If our general partner, with the advice of counsel, determines we are subject to federal, state or local laws or regulations that, in the reasonable determination of our general partner, create a substantial risk of cancellation or forfeiture of any property that we have an interest in because of the nationality, citizenship or other related status of any limited partner (or its owners, to the extent relevant), then our general partner may adopt such amendments to our partnership agreement as it determines necessary or advisable to:

Except as described below regarding a person or group owning 20% or more of any class of units then outstanding, record holders of units on the record date will be entitled to notice of, and to vote at, meetings of our limited partners and to act upon matters for which approvals may be solicited.

Our general partner does not anticipate that any meeting of our unitholders will be called in the foreseeable future. Any action that is required or permitted to be taken by the unitholders may be taken either at a meeting of the unitholders or without a meeting if consents in writing describing the action so taken are signed by holders of the number of units necessary to authorize or take that action at a meeting. Meetings of the unitholders may be called by our general partner or by unitholders owning at least 20% of the outstanding units of the class for which a meeting is proposed. Unitholders may vote either in person or by proxy at meetings. The holders of a majority of the outstanding units of the class or classes for which a meeting has been called, represented in person or by proxy, will constitute a quorum, unless any action by the unitholders requires approval by holders of a greater percentage of the units, in which case the quorum will be the greater percentage. Our general partner may postpone any meeting of unitholders one or more times for any reason by giving notice to the unitholders entitled to vote at such meeting. Our general partner may also adjourn any meeting of unitholders one or more times for any reason, including the absence of a quorum, without a vote of the unitholders.

Each record holder of a unit has a vote according to his percentage interest in us, although additional limited partner interests having special voting rights could be issued. Please read “—Issuance of Additional Interests.” However, if at any time any person or group, other than our general partner and its affiliates (including Oasis), or a direct or subsequently approved transferee of our general partner or its affiliates and purchasers specifically approved by our general partner, acquires, in the aggregate, beneficial ownership of 20% or more of any class of units then outstanding, that person or group will lose voting rights on all of its units and the units may not be voted on any matter and will not be considered to be outstanding when sending notices of a meeting of unitholders, calculating required votes, determining the presence of a quorum or for other similar purposes. Common units held in nominee or street name account will be voted by the broker or other nominee in accordance with the instruction of the beneficial owner unless the arrangement between the beneficial owner and his nominee provides otherwise. Except as our partnership agreement otherwise provides, subordinated units will vote together with common units, as a single class.

Any notice, demand, request, report or proxy material required or permitted to be given or made to record common unitholders under our partnership agreement will be delivered to the record holder by us or by the transfer agent.

Index to Financial Statements

If a majority of the incentive distribution rights are held by our general partner and its affiliates, the holders of the incentive distribution rights will have no right to vote in respect of such rights on any matter, unless otherwise required by law, and the holders of the incentive distribution rights shall be deemed to have approved any matter approved by our general partner.

If less than a majority of the incentive distribution rights are held by our general partner and its affiliates, the incentive distribution rights will be entitled to vote on all matters submitted to a vote of unitholders, other than amendments and other matters that our general partner determines do not adversely affect the holders of the incentive distribution rights in any material respect. On any matter in which the holders of incentive distribution rights are entitled to vote, such holders will vote together with the subordinated units, prior to the end of the subordination period, or together with the common units, thereafter, in either case as a single class, and such incentive distribution rights shall be treated in all respects as subordinated units or common units, as applicable, when sending notices of a meeting of our limited partners to vote on any matter (unless otherwise required by law), calculating required votes, determining the presence of a quorum or for other similar purposes under our partnership agreement. The relative voting power of the holders of the incentive distribution rights and the subordinated units or common units, depending on which class the holders of incentive distribution rights are voting with, will be set in the same proportion as cumulative cash distributions, if any, in respect of the incentive distribution rights for the four consecutive quarters prior to the record date for the vote bears to the cumulative cash distributions in respect of such class of units for such four quarters.

By transfer of common units in accordance with our partnership agreement, each transferee of common units shall be admitted as a limited partner with respect to the common units transferred when such transfer and admission are reflected in our books and records. Except as described under “—Limited Liability,” the common units will be fully paid, and unitholders will not be required to make additional contributions.

Under our partnership agreement, in most circumstances, we will indemnify the following persons, to the fullest extent permitted by law, from and against all losses, claims, damages or similar events:

Any indemnification under these provisions will only be out of our assets. Unless our general partner otherwise agrees, it will not be personally liable for, or have any obligation to contribute or lend funds or assets to us to enable us to effectuate, indemnification. We may purchase insurance against liabilities asserted against and expenses incurred by persons for our activities, regardless of whether we would have the power to indemnify the person against liabilities under our partnership agreement.

Index to Financial Statements

Our partnership agreement requires us to reimburse our general partner for all direct and indirect expenses it incurs or payments it makes on our behalf and all other expenses allocable to us or otherwise incurred by our general partner in connection with operating our business. 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. Our general partner is entitled to determine in good faith 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.”

Our general partner is required to keep appropriate books of our business at our principal offices. These books will be maintained for both tax and financial reporting purposes on an accrual basis. For tax and fiscal reporting purposes, our fiscal year is the calendar year.

We will furnish or make available to record holders of our common units, within 105 days after the close of each fiscal year, an annual report containing audited financial statements and a report on those financial statements by our independent public accountants. Except for our fourth quarter, we will also furnish or make available summary financial information within 50 days after the close of each quarter. We will be deemed to have made any such report available if we file such report with the SEC on EDGAR or make the report available on a publicly available website that we maintain.

We will furnish each record holder with information reasonably required for federal and state tax reporting purposes within 90 days after the close of each calendar year. This information is expected to be furnished in summary form so that some complex calculations normally required of partners can be avoided. Our ability to furnish this summary information to our unitholders will depend on their cooperation in supplying us with specific information. Every unitholder will receive information to assist him in determining his federal and state tax liability and in filing his federal and state income tax returns, regardless of whether he supplies us with the necessary information.

Our partnership agreement provides that a limited partner can, for a purpose reasonably related to his interest as a limited partner, upon reasonable written demand stating the purpose of such demand and at his own expense, have furnished to him:

Under our partnership agreement, however, each of our limited partners and other persons who acquire interests in our partnership interests, do not have rights to receive information from us or any of the persons we indemnify as described above under “—Indemnification” for the purpose of determining whether to pursue litigation or assist in pending litigation against us or those indemnified persons relating to our affairs, except pursuant to the applicable rules of discovery relating to the litigation commenced by the person seeking information.

Index to Financial Statements

Our general partner may, and intends to, keep confidential from the limited partners trade secrets or other information the disclosure of which our general partner determines is not in our best interests or that we are required by law or by agreements with third parties to keep confidential. Our partnership agreement limits the rights to information that a limited partner would otherwise have under Delaware law.

Under our partnership agreement, we have agreed to register for resale under the Securities Act and applicable state securities laws any common units, subordinated units or other limited partner interests proposed to be sold by our general partner or any of its affiliates or their assignees if an exemption from the registration requirements is not otherwise available. These registration rights continue for two years following any withdrawal or removal of our general partner. We are obligated to pay all expenses incidental to the registration, excluding underwriting discounts.

In addition, in connection with the completion of this offering, we expect to enter into a registration rights agreement with Oasis. Pursuant to the registration rights agreement, we will be required to file a registration statement to register the common units and subordinated units issued to Oasis and the common units issuable upon the conversion of the subordinated units upon request of Oasis. Pursuant to the registration rights agreement and our partnership agreement, we may be required to undertake a future public or private offering and use the proceeds (net of underwriting or placement agency discounts, fees and commissions, as applicable) to redeem an equal number of common units from them. In addition, the registration rights agreement gives Oasis “piggyback” registration rights under certain circumstances. The registration rights agreement also includes provisions dealing with holdback agreements, indemnification and contribution and allocation of expenses. These registration rights are transferable to affiliates of Oasis and, in certain circumstances, to third parties. Please read “Units Eligible for Future Sale.”

Index to Financial Statements

After the sale of the common units offered by this prospectus, Oasis will indirectly hold an aggregate of common units and subordinated units. All of the subordinated units will convert into common units at the end of the subordination period and some may convert earlier. The sale of these common and subordinated units could have an adverse impact on the price of the common units or on any trading market that may develop.

Our common units sold in this offering will generally be freely transferable without restriction or further registration under the Securities Act, other than any units purchased in this offering by officers, directors, employees and certain other persons affiliated with us under our directed unit program, which will be subject to the lock-up restrictions described below. None of the directors or officers of our general partner own any common units prior to this offering; however, they may purchase common units through the directed unit program or otherwise. Please read “Underwriting” for a description of these lock-up provisions. Additionally, any common units held by an “affiliate” of ours may not be resold publicly except in compliance with the registration requirements of the Securities Act or under an exemption under Rule 144 or otherwise. Rule 144 permits common units acquired by an affiliate of ours to be sold into the market in an amount that does not exceed, during any three-month period, the greater of:

Sales under Rule 144 are also subject to specific manner of sale provisions, holding period requirements, notice requirements and the availability of current public information about us. A person who is not deemed to have been an affiliate of ours at any time during the 90 days preceding a sale, and who has beneficially owned our common units for at least six months, would be entitled to sell those common units under Rule 144, subject only to the current public information requirement. A person who is not deemed to have been an affiliate of ours at any time during the 90 days preceding a sale, and who has beneficially owned our common units for at least one year, would be entitled to sell those common units under Rule 144 without regard to the other provisions.

Our partnership agreement provides that we may issue an unlimited number of limited partner interests of any type and at any time without a vote of the unitholders. Any issuance of additional common units or other limited partner interests would result in a corresponding decrease in the proportionate ownership interest in us represented by, and could adversely affect the cash distributions to and market price of, common units then outstanding. Please read “The Partnership Agreement—Issuance of Additional Interests.”

Under our partnership agreement, our general partner and its affiliates will have the right to cause us to register under the Securities Act and applicable state securities laws the offer and sale of any units that they hold. Subject to the terms and conditions of our partnership agreement, these registration rights allow our general partner and its affiliates or their assignees holding any units to require registration of any of these units and to include any of these units in a registration by us of other units, including units offered by us or by any unitholder. Our general partner and its affiliates will continue to have these registration rights for two years following its withdrawal or removal as our general partner. In connection with any registration of this kind, we will indemnify each unitholder participating in the registration and its officers, directors and controlling persons from and against any liabilities under the Securities Act or any applicable state securities laws arising from the registration statement or prospectus. We will bear all costs and expenses incidental to any registration, excluding any underwriting discount. Except as described below, our general partner and its affiliates may sell their units in private transactions at any time, subject to compliance with applicable laws.

In addition, we will enter into a registration rights agreement with Oasis pursuant to which we may be required to register the sale of the (i) common units issued (or issuable) to Oasis pursuant to the contribution agreement, (ii) subordinated units and (iii) common units issuable upon conversion of subordinated units pursuant to the terms of the partnership agreement (together, the “Registrable Securities”) it holds. Under the

Index to Financial Statements

registration rights agreement, Oasis will have the right to request that we register the sale of Registrable Securities held by it, and Oasis will have the right to require us to make available shelf registration statements permitting sales of Registrable Securities into the market from time to time over an extended period, subject to certain limitations. Pursuant to the registration rights agreement and our partnership agreement, we may be required to undertake a future public or private offering of common units and use the net proceeds from such offering to redeem an equal number of common units held by Oasis. In addition, the registration rights agreement gives Oasis “piggyback” registration rights under certain circumstances. The registration rights agreement also includes provisions dealing with indemnification and contribution and allocation of expenses. All of the Registrable Securities held by Oasis and any permitted transferee will be entitled to these registration rights. Please read “Certain Relationships and Related Party Transactions—Agreements with Affiliates in Connection with the Transactions—Registration Rights Agreement.”

OMS Holdings and certain of its affiliates, including our general partner and each of our general partner’s directors and officers, have agreed not to sell any common units they beneficially own for a period of 180 days from the date of this prospectus. Participants in our directed unit program will be subject to similar restrictions. Please read “Underwriting” for a description of these lock-up provisions.

In connection with the completion of this offering, certain of our employees, including our executive officers, and/or directors may enter into written trading plans that are intended to comply with Rule 10b5-1 under the Exchange Act. Sales under these trading plans would not be permitted until the expiration of the lock-up agreements relating to the offering described above.

We intend to file a registration statement on Form S-8 under the Securities Act to register shares issuable under the LTIP. This registration statement on Form S-8 is expected to be filed following the effective date of the registration statement of which this prospectus is a part and will be effective upon filing. Accordingly, shares registered under such registration statement may be made available for sale in the open market following the effective date, unless such shares are subject to vesting restrictions with us, Rule 144 restrictions applicable to our affiliates or the lock-up restrictions described above.

Index to Financial Statements

This section summarizes the U.S. material federal income tax consequences that may be relevant to prospective unitholders and is based upon current provisions of the Code, existing and proposed Treasury regulations thereunder (the “Treasury Regulations”) and current administrative rulings and court decisions, all of which are subject to change. Changes in these authorities may cause the federal income tax consequences to a prospective unitholder to vary substantially from those described below, possibly on a retroactive basis. Unless the context otherwise requires, references in this section to “we,” “our,” “us” or “the Partnership” are references to Oasis Midstream Partners LP and its subsidiaries.

Legal conclusions contained in this section, unless otherwise noted, are the opinion of Vinson & Elkins L.L.P. and are based on the accuracy of representations made by us to them for this purpose. However, this section does not address all federal income tax matters that may affect us or our unitholders, such as the application of the alternative minimum tax. This section also does not address local taxes, state taxes, non-U.S. taxes or other taxes that may be applicable, except to the limited extent that such tax considerations are addressed below under “—State, Local and Other Tax Considerations.” Furthermore, this section focuses on unitholders who are individual citizens or residents of the United States (for federal income tax purposes), who have the U.S. dollar as their functional currency, who use the calendar year as their taxable year, who purchase common units in this offering, who do not materially participate in the conduct of our business activities and who hold such common units as capital assets (typically, property that is held for investment). This section has limited applicability to corporations (including other entities treated as corporations for federal income tax purposes), partnerships (including other entities treated as partnerships for federal income tax purposes), estates, trusts, non-resident aliens or other unitholders subject to specialized tax treatment, such as tax-exempt entities, non-U.S. persons, individual retirement accounts (“IRAs”), employee benefit plans, real estate investment trusts or mutual funds. Accordingly, we encourage each prospective unitholder to consult the unitholder’s own tax advisor in analyzing the federal, state, local and non-U.S. tax consequences particular to that unitholder resulting from ownership or disposition of our common units and potential changes in applicable tax laws.

We have requested and received a private letter ruling from the IRS holding that certain of our income constitutes qualifying income. In addition, we will rely on the opinions and advice of Vinson & Elkins L.L.P. with respect to the matters described herein. An opinion of counsel represents only that counsel’s best legal judgment and does not bind the IRS or a court. Accordingly, the opinions and statements made herein may not be sustained by a court if contested by the IRS. Any such contest of the matters described herein may materially and adversely impact the market for our common units and the prices at which our common units trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our distributable cash. Furthermore, the tax consequences of an investment in us may be significantly modified by future legislative or administrative changes or court decisions, which may be retroactively applied.

For the reasons described below, Vinson & Elkins L.L.P. has not rendered an opinion with respect to the following federal income tax issues:

Index to Financial Statements

We expect to be treated as a partnership for U.S. federal income tax purposes and, therefore, subject to the discussion below under “—Administrative Matters—Information Returns and Audit Procedures,” generally will not be liable for entity-level federal income taxes. Instead, as described below, each of our unitholders will take into account its respective share of our items of income, gain, loss and deduction in computing its federal income tax liability as if the unitholder had earned such income directly, even if we make no cash distributions to the unitholder. Distributions we make to a unitholder will not give rise to income or gain taxable to such unitholder unless the amount of cash distributed exceeds the unitholder’s adjusted tax basis in its common units. Please read “—Tax Consequences of Common Unit Ownership—Treatment of Distributions” and “—Disposition of Common Units”).

Section 7704 of the Code provides that a publicly traded partnership will be treated as a corporation for federal income tax purposes. However, if 90% or more of a partnership’s gross income for every taxable year it is publicly traded consists of “qualifying income,” the partnership may continue to be treated as a partnership for federal income tax purposes (the “Qualifying Income Exception”). Qualifying income includes, (i) income and gains derived from the exploration, development, mining or production, processing, transportation or the marketing of any mineral or natural resource (such as natural gas, crude oil and refined products), (ii) interest (other than from a financial business), (iii) dividends, (iv) gains from the sale of real property and (v) gains from the sale or other disposition of capital assets (or property described in Section 1231(b) of the Code) held for the production of income that otherwise constitutes qualifying income. We estimate that less than % of our current gross income is not qualifying income; however, this estimate could change from time to time.

No ruling has been or will be sought from the IRS with respect to our classification as a partnership for federal income tax purposes or as to the classification of limited liability company operating subsidiaries. Instead we have relied on the opinion of counsel that, based upon the Code, existing Treasury Regulations, published revenue rulings and court decisions and representations described below, Oasis Midstream Partners LP and our limited liability company operating subsidiaries will be classified as partnerships for federal income tax purposes.

Vinson & Elkins L.L.P. is of the opinion that we will be treated as a partnership for federal income tax purposes and each of our operating subsidiaries will be treated as a partnerships. In rendering its opinion, Vinson & Elkins L.L.P. has relied on the factual representations made by us and our general partner, including, without limitation:

(a) Neither we nor any of our limited liability company operating subsidiaries has elected or will elect to be treated as a corporation for federal income tax purposes; and

(b) More than 90% of our gross income will be income of a character that Vinson & Elkins L.L.P. has opined is “qualifying income” within the meaning of Section 7704(d) of the Code.

If we fail to meet the Qualifying Income Exception, other than a failure that is determined by the IRS to be inadvertent and that is cured within a reasonable time after discovery (in which case the IRS may also require us to make adjustments with respect to our unitholders or pay other amounts), we will be treated as transferring all of our assets, subject to all of our liabilities, to a newly formed corporation on the first day of the year in which we fail to meet the Qualifying Income Exception in return for stock in that corporation and then as distributing that stock to our unitholders in liquidation. This deemed contribution and liquidation should not result in the recognition of taxable income by our unitholders or us so long as the aggregate amount of our liabilities does not exceed the adjusted tax basis of our assets. Thereafter, we would be treated as an association taxable as a corporation for federal income tax purposes.

Index to Financial Statements

The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative or legislative action or judicial interpretation at any time. From time to time, members of the U.S. Congress have proposed and considered substantive changes to the existing federal income tax laws that would affect publicly traded partnerships. One such legislative proposal would have eliminated the Qualifying Income Exception upon which we rely for our treatment as a partnership for federal income tax purposes.

In addition, on January 24, 2017, the Final Regulations regarding which activities give rise to qualifying income within the meaning of Section 7704 of the Code 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 qualify as a publicly traded partnership.

It is possible that a change in law could affect us and may be applied retroactively. Any such changes could negatively impact the value of an investment in our common units. If for any reason we are taxable as a corporation in any taxable year, our items of income, gain, loss and deduction would be taken into account by us in determining the amount of our liability for federal income tax, rather than being passed through to our unitholders.

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. Imposition of a similar tax on us in the jurisdictions in which we operate or in other jurisdictions to which we may expand 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 federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us. Our taxation as a corporation would materially reduce the distributable cash and thus would likely substantially reduce the value of our common units. Any distribution made to a unitholder at a time when we are treated as a corporation would be (i) a taxable dividend to the extent of our current or accumulated earnings and profits, then (ii) a nontaxable return of capital to the extent of the unitholder’s adjusted tax basis in its common units (determined separately for each common unit), and thereafter (iii) taxable capital gain.

The remainder of this discussion is based on the opinion of Vinson & Elkins L.L.P. that we will be treated as a partnership for federal income tax purposes.

Unitholders of Oasis Midstream Partners LP who are admitted as limited partners of the partnership will be treated as partners of Oasis Midstream Partners LP for federal income tax purposes. Unitholders whose common units are held in street name or by a nominee and who have the right to direct the nominee in the exercise of all substantive rights attendant to the ownership of their common units will be treated as partners of Oasis Midstream Partners LP for federal income tax purposes.

In addition, a beneficial owner of common units whose common units have been transferred to a short seller to complete a short sale would appear to lose their status as a partner with respect to such common units for federal income tax purposes. Please read “—Tax Consequences of Common Unit Ownership—Treatment of Securities Loans.”

Income, gain, deductions or losses would not appear to be reportable by a unitholder who is not a partner for federal income tax purposes, and any cash distributions received by a unitholder who is not a partner for federal

Index to Financial Statements

income tax purposes would therefore appear to be fully taxable as ordinary income. A unitholder who is not treated as a partner in us as described above is urged to consult its own tax advisors with respect to the tax consequences applicable to such unitholder under its particular circumstances.

Subject to the discussion below under “—Entity-Level Collections of Unitholder Taxes” and “—Administrative Matters—Information Returns and Audit Procedures” with respect to payments we may be required to make on behalf of our unitholders, we will not pay any federal income tax. Rather, each unitholder will be required to report on its federal income tax return each year its share of our income, gains, losses and deductions for our taxable year or years ending with or within its taxable year. Consequently, we may allocate income to a unitholder even if that unitholder has not received a cash distribution.

A unitholder’s tax basis in its common units initially will be the amount paid for those common units increased by the unitholder’s initial allocable share of our liabilities. That basis generally will be (i) increased by the unitholder’s share of our income and any increases in such unitholder’s share of our liabilities, and (ii) decreased, but not below zero, by the amount of all distributions to the unitholder, the unitholder’s share of our losses and any decreases in its share of our liabilities. The IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all of those interests.

We estimate that a purchaser of common units in this offering who owns those common units from the date of closing of this offering through the record date for distributions for the period ending , 2017, will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be % or less of the cash distributed on those units with respect to that period. Thereafter, we anticipate that the ratio of allocable taxable income to cash distributions to the unitholders will increase. Our estimate is based upon many assumptions regarding our business operations, including assumptions as to our revenues, capital expenditures, cash flow, net working capital and anticipated cash distributions. These estimates and assumptions are subject to, among other things, numerous business, economic, regulatory, legislative, competitive and political uncertainties beyond our control. Further, the estimates are based on current tax law and tax reporting positions that we will adopt and with which the IRS could disagree. Accordingly, we cannot assure you that these estimates will prove to be correct, and our counsel has not opined on the accuracy of such estimates.

The ratio of taxable income to cash distributions for a purchaser of our common units in this offering would be higher, and perhaps substantially higher, than our estimate with respect to the period described above if:

Distributions made by us to a unitholder generally will not be taxable to the unitholder unless such distributions are of cash or marketable securities that are treated as cash and exceed the unitholder’s tax basis in its common units, in which case the unitholder generally will recognize gain taxable in the manner described below under “—Disposition of Common Units.”

Index to Financial Statements

Any reduction in a unitholder’s share of our “nonrecourse liabilities” (liabilities for which no partner bears the economic risk of loss) will be treated as a distribution by us of cash to that unitholder. A decrease in a unitholder’s percentage interest in us because of our issuance of additional common units may decrease such unitholder’s share of our nonrecourse liabilities. For purposes of the foregoing, a unitholder’s share of our nonrecourse liabilities generally will be based upon such unitholder’s share of the unrealized appreciation (or depreciation) in our assets, to the extent thereof, with any excess nonrecourse liabilities allocated based on the unitholder’s share of our profits. Please read “—Disposition of Common Units.”

A non-pro rata distribution of money or property (including a deemed distribution as a result of the reallocation of our nonrecourse liabilities described above) may cause a unitholder to recognize ordinary income if the distribution reduces the unitholder’s share of our “unrealized receivables,” including depreciation recapture and substantially appreciated “inventory items,” both as defined in Section 751 of the Code (“Section 751 Assets”). To the extent of such reduction, the unitholder would be deemed to receive its proportionate share of the Section 751 Assets and exchange such assets with us in return for a portion of the non-pro rata distribution. This deemed exchange will generally result in the unitholder’s recognition of ordinary income in an amount equal to the excess of (1) the non-pro rata portion of that distribution over (2) the unitholder’s tax basis (typically zero) in the Section 751 Assets deemed to be relinquished in the exchange.

A unitholder may not be entitled to deduct the full amount of loss we allocate to it because its share of our losses will be limited to the lesser of (i) the unitholder’s adjusted tax basis in its common units and (ii) in the case of a unitholder that is an individual, estate, trust or certain types of closely-held corporations, the amount for which the unitholder is considered to be “at risk” with respect to our activities. A unitholder will be at risk to the extent of its adjusted tax basis in its common units, reduced by (1) any portion of that basis attributable to the unitholder’s share of our nonrecourse liabilities, (2) any portion of that basis representing amounts otherwise protected against loss because of a guarantee, stop loss agreement or similar arrangement and (3) any amount of money the unitholder borrows to acquire or hold its common units, if the lender of those borrowed funds owns an interest in us, is related to another unitholder or can look only to the common units for repayment. A unitholder subject to the at risk limitation must recapture losses deducted in previous years to the extent that distributions (including distributions deemed to result from a reduction in a unitholder’s share of nonrecourse liabilities) cause the unitholder’s at risk amount to be less than zero at the end of any taxable year.

Losses disallowed to a unitholder or recaptured as a result of the basis or at risk limitations will carry forward and will be allowable as a deduction in a later year to the extent that the unitholder’s adjusted tax basis or at risk amount, whichever is the limiting factor, is subsequently increased. Upon a taxable disposition of our common units, any gain recognized by a unitholder can be offset by losses that were previously suspended by the at risk limitation but not losses suspended by the basis limitation. Any loss previously suspended by the at risk limitation in excess of that gain can no longer be used and will not be available to offset a unitholder’s salary or active business income.

In addition to the basis and at risk limitations, a passive activity loss limitation limits the deductibility of losses incurred by individuals, estates, trusts, some closely-held corporations and personal service corporations from “passive activities” (such as trade or business activities in which the taxpayer does not materially participate). The passive loss limitations are applied separately with respect to each publicly traded partnership. Consequently, any passive losses we generate will be available to offset only passive income generated by us. Passive losses that exceed a unitholder’s share of the passive income we generate may be deducted in full when a unitholder disposes of all of its common units in a fully taxable transaction with an unrelated party. The passive loss rules are applied after other applicable limitations on deductions, including the at risk and basis limitations.

Index to Financial Statements

The deductibility of a non-corporate taxpayer’s “investment interest expense” is generally limited to the amount of that taxpayer’s “net investment income.” Investment interest expense includes:

The computation of a unitholder’s investment interest expense will take into account interest on any margin account borrowing or other loan incurred to purchase or carry a common unit. Net investment income includes gross income from property held for investment and amounts treated as portfolio income under the passive loss rules, less deductible expenses, other than interest directly connected with the production of investment income. Net investment income does not include qualified dividend income (if applicable) or gains attributable to the disposition of property held for investment. A unitholder’s share of a publicly traded partnership’s portfolio income and, according to the IRS, net passive income will be treated as investment income for purposes of the investment interest expense limitation.

If we are required or elect under applicable law to pay any federal, state, local or non-U.S. tax on behalf of any current or former unitholder or our general partner, our partnership agreement authorizes us to treat the payment as a distribution of cash to the relevant unitholder or general partner. Where the tax is payable on behalf of all unitholders or we cannot determine the specific unitholder on whose behalf the tax is payable, our partnership agreement authorizes us to treat the payment as a distribution to all current unitholders. Payments by us as described above could give rise to an overpayment of tax on behalf of a unitholder, in which event the unitholder may be entitled to claim a refund of the overpayment amount. Please read “—Administrative Matters—Information Returns and Audit Procedures.” Each unitholder is urged to consult its tax advisor to determine the consequences to them of any tax payment we make on its behalf.

Except as described below, our items of income, gain, loss and deduction will be allocated among our unitholders in accordance with their percentage interests in us. At any time that distributions are made on our common units in excess of distributions on our subordinated units, or we make incentive distributions, gross income will be allocated to the recipients to the extent of these distributions.

Specified items of our income, gain, loss and deduction will be allocated under Section 704(c) of the Code (or the principles of Section 704(c) of the Code) to account for any difference between the adjusted tax basis and fair market value of our assets at the time such assets are contributed to us and at the time of any subsequent offering of our units (a “Book-Tax Disparity”). As a result, the federal income tax burden associated with any Book-Tax Disparity immediately prior to an offering will be borne by our partners holding interests in us prior to such offering. In addition, items of recapture income will be specially allocated to the extent possible (subject to the limitations described above) to the unitholder who was allocated the deduction giving rise to that recapture income in order to minimize the recognition of ordinary income by other unitholders.

An allocation of items of our income, gain, loss or deduction, other than an allocation required by the Code to eliminate a Book-Tax Disparity, will be given effect for federal income tax purposes in determining a unitholder’s share of an item of income, gain, loss or deduction only if the allocation has “substantial economic effect.” In any other case, a unitholder’s share of an item will be determined on the basis of the unitholder’s interest in us, which will be determined by taking into account all the facts and circumstances, including (i) the

Index to Financial Statements

unitholder’s relative contributions to us, (ii) the interests of all the partners in profits and losses, (iii) the interest of all the partners in cash flow and (iv) the rights of all the partners to distributions of capital upon liquidation. Vinson & Elkins L.L.P. is of the opinion that, with the exception of the issues described in “—Section 754 Election” and “—Disposition of Common Units—Allocations Between Transferors and Transferees,” allocations of income, gain, loss or deduction under our partnership agreement will be given effect for federal income tax purposes.

A unitholder whose common units are the subject of a securities loan (for example, a loan to a “short seller” to cover a short sale of our common units) may be treated as having disposed of those common units. If so, such unitholder 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 as a result of such deemed disposition. As a result, during this period (i) any of our income, gain, loss or deduction allocated to those common units would not be reportable by the lending unitholder and (ii) any cash distributions received by the lending unitholder as to those common units may be treated as ordinary taxable income.

Due to a lack of controlling authority, Vinson & Elkins L.L.P. has not rendered an opinion regarding the tax treatment of a unitholder that enters into a securities loan with respect to its common units. A unitholder desiring to assure its status as partners and avoid the risk of income recognition from a loan of its common units is urged to modify any applicable brokerage account agreements to prohibit its brokers from borrowing and lending its common units. The IRS has announced that it is studying issues relating to the tax treatment of short sales of partnership interests. Please read “—Disposition of Common Units—Recognition of Gain or Loss.”

Under current law, the highest marginal federal income tax rates for individuals applicable to ordinary income and long-term capital gains (generally, gains from the sale or exchange of certain investment assets held for more than one year) are 39.6% and 20%, respectively. These rates are subject to change by new legislation at any time.

In addition, a 3.8% net investment income tax applies to certain net investment income earned by individuals, estates and trusts. For these purposes, net investment income generally includes a unitholder’s allocable share of our income and gain realized by a unitholder from a sale of our common units. In the case of an individual, the tax will be imposed on the lesser of (i) the unitholder’s net investment income from all investments or (ii) the amount by which the unitholder’s modified adjusted gross income exceeds $250,000 (if the unitholder is married and filing jointly or a surviving spouse), $125,000 (if married filing separately) or $200,000 (if the unitholder is unmarried or in any other case). In the case of an estate or trust, the tax will be imposed on the lesser of (i) undistributed net investment income or (ii) the excess adjusted gross income over the dollar amount at which the highest income tax bracket applicable to an estate or trust begins.

We have made the election permitted by Section 754 of the Code that permits us to adjust the tax basis in each of our assets as to specific purchasers of our common units under Section 743(b) of the Code to reflect the common unit purchase price upon subsequent purchases of common units. That election is irrevocable without the consent of the IRS. The Section 743(b) adjustment separately applies to a unitholder who purchases common units from another unitholder based upon the values and adjusted tax basis of each of our assets at the time of the relevant purchase, and the adjustment will reflect the purchase price paid. The Section 743(b) adjustment does not apply to a person who purchases common units directly from us. For purposes of this discussion, a unitholder’s basis in our assets will be considered to have two components: (1) its share of the tax basis in our assets as to all unitholders and (2) its Section 743(b) adjustment to that tax basis (which may be positive or negative).

Index to Financial Statements

Under our partnership agreement, we are authorized to take a position to preserve the uniformity of common units even if that position is not consistent with applicable Treasury Regulations. A literal application of Treasury Regulations governing a 743(b) adjustment attributable to properties depreciable under Section 167 of the Code may give rise to differences in the taxation of unitholders purchasing common units from us and unitholders purchasing from other unitholders. If we have any such properties, we intend to adopt methods employed by other publicly traded partnerships to preserve the uniformity of common units, even if inconsistent with existing Treasury Regulations, and Vinson & Elkins L.L.P. has not opined on the validity of this approach. Please read “—Uniformity of Common Units.”

The IRS may challenge the positions we adopt with respect to depreciating or amortizing the Section 743(b) adjustment to preserve the uniformity of common units due to lack of controlling authority. Because a unitholder’s adjusted tax basis for its common units is reduced by its share of our items of deduction or loss, any position we take that understates deductions will overstate a unitholder’s basis in its common units and may cause the unitholder to understate gain or overstate loss on any sale of such common units. Please read “—Disposition of Common Units—Recognition of Gain or Loss.” If a challenge to such treatment were sustained, the gain from the sale of our common units may be increased without the benefit of additional deductions.

The calculations involved in the Section 754 election are complex and are made on the basis of assumptions as to the value of our assets and other matters. The IRS could seek to reallocate some or all of any Section 743(b) adjustment we allocated to our depreciable assets to goodwill or nondepreciable assets. Goodwill, as an intangible asset, is amortizable over a longer period of time or under a less accelerated method than certain of our tangible assets. We cannot assure any unitholder that the determinations we make will not be successfully challenged by the IRS or that the resulting deductions will not be reduced or disallowed altogether. Should the IRS require a different tax basis adjustment to be made, and should, in our opinion, the expense of compliance exceed the benefit of the election, we may seek permission from the IRS to revoke our Section 754 election. If permission is granted, a subsequent purchaser of common units may be allocated more income than it would have been allocated had the election not been revoked.

We will use the year ending December 31 as our taxable year and the accrual method of accounting for federal income tax purposes. Each unitholder will be required to include in its tax return its share of our income, gain, loss and deduction for each taxable year ending within or with its taxable year. In addition, a unitholder who has a taxable year ending on a date other than December 31 and who disposes of all of its common units following the close of our taxable year but before the close of its taxable year must include its share of our income, gain, loss and deduction in income for its taxable year, with the result that it will be required to include in income for its taxable year its share of more than twelve months of our income, gain, loss and deduction. Please read “—Disposition of Common Units—Allocations Between Transferors and Transferees.”

The tax basis of each of our assets will be used for purposes of computing depreciation and cost recovery deductions and, ultimately, gain or loss on the disposition of these assets. If we dispose of depreciable property by sale, foreclosure or otherwise, all or a portion of any gain, determined by reference to the amount of depreciation and deductions previously taken, may be subject to the recapture rules and taxed as ordinary income rather than capital gain. Similarly, a unitholder who has taken cost recovery or depreciation deductions with respect to property we own will likely be required to recapture some or all of those deductions as ordinary income upon a sale of its interest in us. Please read “—Tax Consequences of Common Unit Ownership—Allocation of Income, Gain, Loss and Deduction” and “—Disposition of Common Units – Recognition of Gain or Loss.”

Index to Financial Statements

The costs we incur in offering and selling our common units (called “syndication expenses”) must be capitalized and cannot be deducted currently, ratably or upon our termination. While there are uncertainties regarding the classification of certain costs as organization expenses, which may be amortized by us, and as syndication expenses, which may not be amortized by us, the underwriting discounts and commissions we incur will be treated as syndication expenses. Please read “—Disposition of Common Units—Recognition of Gain or Loss.”

The federal income tax consequences of the ownership and disposition of common units will depend in part on our estimates of the relative fair market values and the tax basis of each of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we will make many of the relative fair market value estimates ourselves. These estimates and determinations of tax basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or tax basis are later found to be incorrect, the character and amount of items of income, gain, loss or deduction previously reported by a unitholder could change, and such unitholder could be required to adjust its tax liability for prior years and incur interest and penalties with respect to those adjustments.

A unitholder will be required to recognize gain or loss on a sale or exchange of a common unit equal to the difference, if any, between the unitholder’s amount realized and the adjusted tax basis in the common unit sold. A unitholder’s amount realized generally will equal the sum of the cash and the fair market value of other property it receives plus its share of our nonrecourse liabilities with respect to the common unit sold or exchanged. Because the amount realized includes a unitholder’s share of our nonrecourse liabilities, the gain recognized on the sale or exchange of a common unit could result in a tax liability in excess of any cash received from such sale or exchange.

Except as noted below, gain or loss recognized by a unitholder on the sale or exchange of a common unit held for more than one year generally will be taxable as long-term capital gain or loss. However, gain or loss recognized on the disposition of our common units will be separately computed and taxed as ordinary income or loss under Section 751 of the Code to the extent attributable to Section 751 Assets, such as depreciation recapture and our “inventory items,” regardless of whether such inventory item has substantially appreciated in value. Ordinary income attributable to Section 751 Assets may exceed net taxable gain realized on the sale or exchange of a common unit and may be recognized even if there is a net taxable loss realized on the sale or exchange of a common unit. Thus, a unitholder may recognize both ordinary income and capital gain or loss upon a sale or exchange of a common unit. Net capital loss may offset capital gains and, in the case of individuals, up to $3,000 of ordinary income per year.

For purposes of calculating gain or loss on the sale or exchange of a common unit, the unitholder’s adjusted tax basis will be adjusted by its allocable share of our income or loss in respect of its common unit for the year of the sale. Furthermore, as described above, the IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all those interests. Upon a sale or other disposition of less than all of those interests, a portion of that tax basis must be allocated to the interests sold using an “equitable apportionment” method, which generally means that the tax basis allocated to the interest sold equals an amount that bears the same relation to the partner’s tax basis in its entire interest in the partnership as the value of the interest sold bears to the value of the partner’s entire interest in the partnership.

Treasury Regulations under Section 1223 of the Code allow a selling unitholder who can identify common units transferred with an ascertainable holding period to elect to use the actual holding period of the common

Index to Financial Statements

units transferred. Thus, according to the ruling discussed in the paragraph above, a unitholder will be unable to select high or low basis common units to sell or exchange as would be the case with corporate stock, but, according to the Treasury Regulations, such unitholder may designate specific common units sold for purposes of determining the holding period of the common units transferred. A unitholder electing to use the actual holding period of any common unit transferred must consistently use that identification method for all subsequent sales or exchanges of our common units. A unitholder considering the purchase of additional common units or a sale or exchange of common units purchased in separate transactions is urged to consult its tax advisor as to the possible consequences of this ruling and application of the Treasury Regulations.

Specific provisions of the Code affect the taxation of some financial products and securities, including partnership interests, by treating a taxpayer as having sold an “appreciated” financial position, including a partnership interest with respect to which gain would be recognized if it were sold, assigned or terminated at its fair market value, in the event the taxpayer or a related person enters into:

Moreover, if a taxpayer has previously entered into a short sale, an offsetting notional principal contract or a futures or forward contract with respect to the partnership interest, the taxpayer will be treated as having sold that position if the taxpayer or a related person then acquires the partnership interest or substantially identical property. The Secretary of the Treasury is authorized to issue Treasury Regulations that treat a taxpayer that enters into transactions or positions that have substantially the same effect as the preceding transactions as having constructively sold the financial position. Please read “—Tax Consequences of Common Unit Ownership—Treatment of Securities Loans.”

In general, our taxable income or loss will be determined annually, will be prorated on a monthly basis and will be subsequently apportioned among the unitholders in proportion to the number of common units owned by each of them as of the opening of the applicable exchange on the first business day of the month (the “Allocation Date”). Nevertheless, we allocate certain deductions for depreciation of capital additions based upon the date the underlying property is placed in service, and gain or loss realized on a sale or other disposition of our assets or, in the discretion of the general partner, any other extraordinary item of income, gain, loss or deduction will be allocated among the unitholders on the Allocation Date in the month in which such income, gain, loss or deduction is recognized. As a result, a unitholder transferring common units may be allocated income, gain, loss and deduction realized after the date of transfer.

Although simplifying conventions are contemplated by the Code and most publicly traded partnerships use similar simplifying conventions, existing Treasury Regulations do not specifically authorize the use of the proration method we have adopted. Accordingly, Vinson & Elkins L.L.P. is unable to opine on the validity of this method of allocating income and deductions between transferee and transferor unitholders. If the IRS determines that this method is not allowed under the Treasury Regulations, our taxable income or losses could be reallocated among our unitholders. Under our partnership agreement, we are authorized to revise our method of allocation between transferee and transferor unitholders, as well as among unitholders whose interests vary during a taxable year, to conform to a method permitted under the Treasury Regulations.

A unitholder who disposes of common units prior to the record date set for a cash distribution for that quarter will be allocated items of our income, gain, loss and deduction attributable to the month of disposition but will not be entitled to receive a cash distribution for that period.

Index to Financial Statements

A unitholder who sells or exchanges any common units is generally required to notify us in writing of that transaction within 30 days after the transaction (or, if earlier, January 15 of the year following the transaction in the case of a seller). Upon receiving such notifications, we are required to notify the IRS of the transaction and to furnish specified information to the transferor and transferee. Failure to notify us of a transfer of common units may, in some cases, lead to the imposition of penalties. However, these reporting requirements do not apply to a sale by an individual who is a citizen of the United States and who effects the sale or exchange through a broker who will satisfy such requirements.

We will be considered to have technically terminated our partnership for federal income tax purposes upon the sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of measuring whether the 50% threshold is reached, multiple sales of the same common unit are counted only once. A technical termination results in the closing of our taxable year for all unitholders. In the case of a unitholder reporting on a taxable year other than the calendar year, the closing of our taxable year may result in more than twelve months of our taxable income or loss being includable in such unitholder’s taxable income for the year of termination.

A technical termination occurring on a date other than December 31 would require that we file two tax returns for one fiscal year, thereby increasing our administration and tax preparation costs. However, pursuant to an IRS relief procedure the IRS may allow a technically terminated partnership to provide a single Schedule K-1 for the calendar year in which a termination occurs. Following a technical termination, we would be required to make new tax elections, including a new election under Section 754 of the Code, and the termination would result in a deferral of our deductions for depreciation and thus may increase the taxable income allocable to our unitholders. A technical termination could also result in penalties if we were unable to determine that the technical termination had occurred. Moreover, a technical termination may either accelerate the application of, or subject us to, any tax legislation enacted before the technical termination that would not otherwise have been applied to us as a continuing partnership as opposed to a terminating partnership.

Because we cannot match transferors and transferees of common units and for other reasons, we must maintain uniformity of the economic and tax characteristics of the common units to a purchaser of these common units. As a result of the need to preserve uniformity, we may be unable to completely comply with a number of federal income tax requirements. Any non-uniformity could have a negative impact on the value of our common units. Please read “—Tax Consequences of Common Unit Ownership—Section 754 Election.”

Our partnership agreement permits our general partner to take positions in filing our tax returns that preserve the uniformity of our common units. These positions may include reducing the depreciation, amortization or loss deductions to which a unitholder would otherwise be entitled or reporting a slower amortization of Section 743(b) adjustments for some unitholders than that to which they would otherwise be entitled. Vinson & Elkins L.L.P. is unable to opine as to the validity of such filing positions.

A unitholder’s adjusted tax basis in common units is reduced by its share of our deductions (whether or not such deductions were claimed on an individual income tax return) so that any position that we take that understates deductions will overstate the unitholder’s basis in its common units and may cause the unitholder to understate gain or overstate loss on any sale of such common units. Please read “—Disposition of Common Units—Recognition of Gain or Loss” and “—Tax Consequences of Common Unit Ownership—Section 754 Election” above. The IRS may challenge one or more of any positions we take to preserve the uniformity of our common units. If such a challenge were sustained, the uniformity of our common units might be affected, and, under some circumstances, the gain from any sale of our common units might be increased without the benefit of additional deductions.

Index to Financial Statements

Ownership of our common units by employee benefit plans and other tax-exempt organizations, as well as by non-resident alien individuals, non-U.S. corporations and other non-U.S. persons (collectively, “Non-U.S. Unitholders”) raises issues unique to those investors and, as described below, may have substantially adverse tax consequences to them. Each prospective unitholder that is a tax-exempt entity or a Non-U.S. Unitholder should consult its tax advisors before investing in our common units.

Employee benefit plans and most other tax-exempt organizations, including IRAs and other retirement plans, are subject to federal income tax on unrelated business taxable income. Virtually all of our income will be unrelated business taxable income and will be taxable to a tax-exempt unitholder.

Non-U.S. Unitholders are taxed by the United States on income effectively connected with a U.S. trade or business (“effectively connected income”) and on certain types of U.S.-source non-effectively connected income (such as dividends) unless exempted or further limited by an income tax treaty. Each Non-U.S. Unitholder will be considered to be engaged in business in the United States because of its ownership of our common units. Furthermore, it is probable that Non-U.S. Unitholders will be deemed to conduct such activities through a permanent establishment in the United States within the meaning of an applicable tax treaty. Consequently, each Non-U.S. Unitholder will be required to file federal tax returns to report its share of our income, gain, loss or deduction and pay federal income tax on its share of our net income or gain. Moreover, under rules applicable to publicly traded partnerships, distributions to Non-U.S. Unitholders are subject to withholding at the highest applicable effective tax rate. Each Non-U.S. Unitholder must obtain a taxpayer identification number from the IRS and submit that number to our transfer agent on a Form W-8BEN or W-8BEN-E (or other applicable or successor form) in order to obtain credit for these withholding taxes.

In addition, if a Non-U.S. Unitholder is classified as a non-U.S. corporation, it will be treated as engaged in a United States trade or business and may be subject to the U.S. branch profits tax at a rate of 30%, in addition to regular U.S. federal income tax, on its share of our income and gain as adjusted for changes in the foreign corporation’s “U.S. net equity” to the extent reflected in the corporation’s earnings and profits. That tax may be reduced or eliminated by an income tax treaty between the United States and the country in which the foreign corporate unitholder is a “qualified resident.” In addition, this type of unitholder is subject to special information reporting requirements under Section 6038C of the Code.

A Non-U.S. Unitholder who sells or otherwise disposes of a common unit will be subject to U.S. federal income tax on gain realized from the sale or disposition of that common unit to the extent the gain is effectively connected with a U.S. trade or business of the Non-U.S. Unitholder. Under a ruling published by the IRS interpreting the scope of “effectively connected income,” gain realized by a Non-U.S. Unitholder from the sale of its interest in a partnership that is engaged in a trade or business in the United States will be considered to be “effectively connected” with a U.S. trade or business. Thus, part or all of a Non-U.S. Unitholder’s gain from the sale or other disposition of our common units may be treated as effectively connected with a unitholder’s indirect U.S. trade or business constituted by its investment in us.

Moreover, under the Foreign Investment in Real Property Tax Act, as long as our common units continue to be regularly traded on an established securities market, a Non-U.S. Unitholder generally will only be subject to federal income tax upon the sale or disposition of a common unit if at any time during the shorter of the five-year period ending on the date of the disposition or the Non-U.S. Unitholder’s holding period for the common unit (i) such Non-U.S. Unitholder owned (directly, indirectly or constructively applying certain attribution rules) more than 5% of our common units and (ii) 50% or more of the fair market value of our real property interests and other assets used or held for use in a trade or business consisted of U.S. real property interests (which include U.S. real estate, including land, improvements and associated personal property, and interests in certain entities holding U.S. real estate). If our common units were not considered to be regularly traded on an established securities market, such Non-U.S. Unitholder (regardless of the percentage of common units owned) would be subject to U.S. federal income tax on a taxable disposition of our common units, and a withholding tax would

Index to Financial Statements

apply to the gross proceeds from such disposition (as described in the preceding paragraph). More than 50% of our assets may consist of U.S. real property interests. Therefore, each Non-U.S. Unitholder may be subject to federal income tax on gain from the sale or disposition of its common units.

We intend to furnish to each unitholder, within 90 days after the close of each taxable year, specific tax information, including a Schedule K-1, which describes its share of our income, gain, loss and deduction for our preceding taxable year. In preparing this information, which will not be reviewed by counsel, we will take various accounting and reporting positions, some of which have been mentioned earlier, to determine each unitholder’s share of income, gain, loss and deduction. We cannot assure our unitholders that those positions will yield a result that conforms to all of the requirements of the Code, Treasury Regulations or administrative interpretations of the IRS.

The IRS may audit our federal income tax information returns. Neither we nor Vinson & Elkins L.L.P. can assure prospective unitholders that the IRS will not successfully challenge the positions we adopt, and such a challenge could adversely affect the value of our common units. Adjustments resulting from an IRS audit may require each unitholder to adjust a prior year’s tax liability and may result in an audit of the unitholder’s own return. Any audit of a unitholder’s return could result in adjustments unrelated to our returns.

Publicly traded partnerships are treated as entities separate from their owners for purposes of federal income tax audits, judicial review of administrative adjustments by the IRS and tax settlement proceedings. The tax treatment of partnership items of income, gain, loss and deduction are determined in a partnership proceeding rather than in separate proceedings for each of the partners. The Code requires that one partner be designated as the “Tax Matters Partner” for these purposes, and our partnership agreement designates our general partner as our Tax Matters Partner.

The Tax Matters Partner can extend the statute of limitations for assessment of tax deficiencies against unitholders for items in our tax returns. The Tax Matters Partner may bind a unitholder with less than a 1% profits interest in us to a settlement with the IRS unless that unitholder elects, by filing a statement with the IRS, not to give that authority to the Tax Matters Partner. The Tax Matters Partner may seek judicial review, by which all the unitholders are bound, of a final partnership administrative adjustment and, if the Tax Matters Partner fails to seek judicial review, judicial review may be sought by any unitholder having at least a 1% interest in profits or by any group of unitholders having in the aggregate at least a 5% interest in profits. However, only one action for judicial review may go forward, and each unitholder with an interest in the outcome may participate in that action.

A unitholder must file a statement with the IRS identifying the treatment of any item on its federal income tax return that is not consistent with the treatment of the item on our return. Intentional or negligent disregard of this consistency requirement may subject a unitholder to substantial penalties.

Pursuant to the Bipartisan Budget Act of 2015, for taxable years beginning after December 31, 2017, if the IRS makes audit adjustments to our income tax returns, it may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us unless we elect to have our general partner and unitholders take any audit adjustment into account in accordance with their interests in us during the taxable year under audit. Similarly, for such taxable years, if the IRS makes audit adjustments to income tax returns filed by an entity in which we are a member or partner, it may assess and collect any taxes (including penalties and interest) resulting from such audit adjustment directly from such entity. Generally, we expect to elect to have our general partner and unitholders take any such audit adjustment into account in accordance with their interests in us during the taxable year under audit, but there can be no assurance that such

Index to Financial Statements

election will be effective in all circumstances. With respect to audit adjustments as to an entity in which we are a member or partner, the Joint Committee of Taxation has stated that we would not be able to have our general partner and our unitholders take such audit adjustment into account. If we are unable to have our general partner and our unitholders take such audit adjustment into account in accordance with their interests in us during the taxable year under audit, our then current unitholders may bear some or all of the tax liability resulting from such audit adjustment, even if such unitholders did not own our common units during the taxable year under audit. If, as a result of any such audit adjustment, we are required to make payments of taxes, penalties or interest, our distributable cash might be substantially reduced. These rules are not applicable for taxable years beginning on or prior to December 31, 2017. Congress has proposed changes to the Bipartisan Budget Act, and we anticipate that amendments may be made. Accordingly, the manner in which these rules may apply to us in the future is uncertain.

Additionally, pursuant to the Bipartisan Budget Act of 2015, the Code will no longer require that we designate a Tax Matters Partner. Instead, for taxable years beginning after December 31, 2017, we will be required to designate a partner, or other person, with a substantial presence in the United States as the partnership representative (“Partnership Representative”). The Partnership Representative will have the sole authority to act on our behalf for purposes of, among other things, federal income tax audits and judicial review of administrative adjustments by the IRS. If we do not make such a designation, the IRS can select any person as the Partnership Representative. We currently anticipate that we will designate our general partner as the Partnership Representative. Further, any actions taken by us or by the Partnership Representative on our behalf with respect to, among other things, federal income tax audits and judicial review of administrative adjustments by the IRS will be binding on us and all of our unitholders.

Withholding taxes may apply to certain types of payments made to “foreign financial institutions” (as specially defined in the Code) and certain other non-U.S. entities. Specifically, a 30% withholding tax may be imposed on interest, dividends and other fixed or determinable annual or periodic gains, profits and income from sources within the United States (“FDAP Income”) or gross proceeds from the sale or other disposition of any property of a type which can produce interest or dividends from sources within the United States (“Gross Proceeds”) paid to a foreign financial institution or to a “non-financial foreign entity” (as specially defined in the Code) unless (i) the foreign financial institution undertakes certain diligence and reporting, (ii) the non-financial foreign entity either certifies it does not have any substantial U.S. owners or furnishes identifying information regarding each substantial U.S. owner or (iii) the foreign financial institution or non-financial foreign entity otherwise qualifies for an exemption from these rules. If the payee is a foreign financial institution and is subject to the diligence and reporting requirements in clause (i) above, it must enter into an agreement with the U.S. Department of the Treasury requiring, among other things, that it undertake to identify accounts held by certain U.S. persons or U.S.-owned foreign entities, annually report certain information about such accounts and withhold 30% on payments to noncompliant foreign financial institutions and certain other account holders. Foreign financial institutions located in jurisdictions that have an intergovernmental agreement with the United States governing these requirements may be subject to different rules.

Generally, these rules apply to current payments of FDAP Income and will apply to payments of relevant Gross Proceeds made on or after January 1, 2019. Thus, to the extent we have FDAP Income or we have Gross Proceeds on or after January 1, 2019 that are not treated as effectively connected with a U.S. trade or business (please read “—Tax-Exempt Organizations and Other Investors”), a unitholder that is a foreign financial institution or certain other non-U.S. entity, or a person that hold its common units through such foreign entities, may be subject to withholding on distributions they receive from us, or its distributive share of our income, pursuant to the rules described above.

Each prospective unitholder should consult its own tax advisors regarding the potential application of these withholding provisions to its investment in our common units.

Index to Financial Statements

Persons who hold an interest in us as a nominee for another person are required to furnish to us:

Each broker and financial institution is required to furnish additional information, including whether such broker or financial institution is a U.S. person and specific information on any common units such broker or financial institution acquires, holds or transfers for its own account. A penalty of $250 per failure, up to a maximum of $3 million per calendar year, is imposed by the Code for failure to report that information to us. The nominee is required to supply the beneficial owner of our common units with the information furnished to us.

Certain penalties may be imposed as a result of an underpayment of tax that is attributable to one or more specified causes, including negligence or disregard of rules or regulations, substantial understatements of income tax and substantial valuation misstatements. No penalty will be imposed, however, for any portion of an underpayment if it is shown that there was a reasonable cause for the underpayment of that portion and that the taxpayer acted in good faith regarding the underpayment of that portion. We do not anticipate that any accuracy-related penalties will be assessed against us.

In addition to federal income taxes, unitholders may be subject to other taxes, including state and local income taxes, unincorporated business taxes and estate, inheritance or intangibles taxes that may be imposed by the various jurisdictions in which we conduct business or own property now or in the future or in which the unitholder is a resident. We conduct business or own property in many states in the United States. Some of these states may impose an income tax on individuals, corporations and other entities. As we make acquisitions or expand our business, we may own property or conduct business in additional states that impose a personal income tax. Although an analysis of those various taxes is not presented here, each prospective unitholder should consider the potential impact of such taxes on its investment in us.

A unitholder may be required to file income tax returns and pay income taxes in some or all of the jurisdictions in which we do business or own property, though such unitholder may not be required to file a return and pay taxes in certain jurisdictions because its income from such jurisdictions falls below the jurisdiction’s filing and payment requirement. Further, a unitholder may be subject to penalties for a failure to comply with any filing or payment requirement applicable to such unitholder. Some of the jurisdictions may require us, or we may elect, to withhold a percentage of income from amounts to be distributed to a unitholder who is not a resident of the jurisdiction. Withholding, the amount of which may be greater or less than a particular unitholder’s income tax liability to the jurisdiction, generally does not relieve a nonresident unitholder from the obligation to file an income tax return.

Index to Financial Statements

It is the responsibility of each unitholder to investigate the legal and tax consequences, under the laws of pertinent jurisdictions, of its investment in us. We strongly recommend that each prospective unitholder consult, and depend upon, its own tax counsel or other advisor with regard to those matters. Further, it is the responsibility of each unitholder to file all state, local and non-U.S., as well as federal, tax returns that may be required of it. Vinson & Elkins L.L.P. has not rendered an opinion on the state, local, alternative minimum tax or non-U.S. tax consequences of an investment in us.

Index to Financial Statements

An investment in our common units by an employee benefit plan is subject to additional considerations because the investments of these plans are subject to the fiduciary responsibility and prohibited transaction provisions of ERISA and the prohibited transaction restrictions imposed by Section 4975 of the Code and may be subject to provisions under any federal, state, local, non-U.S. or other laws or regulations that are similar to such provisions of ERISA or the Code (collectively, “Similar Laws”). For these purposes the term “employee benefit plan” includes, but is not limited to, qualified pension, profit-sharing and stock bonus plans, Keogh plans, simplified employee pension plans and tax deferred annuities or IRAs or annuities established or maintained by an employer or employee organization, and entities whose underlying assets are considered to include “plan assets” of such plans, accounts and arrangements. In considering an investment in our common units, among other things, consideration should be given to:

The person with investment discretion with respect to the assets of an employee benefit plan, often called a fiduciary, should determine whether an investment in our common units is authorized by the appropriate governing instruments and is a proper investment for the employee benefit plan.

Section 406 of ERISA and Section 4975 of the Code prohibit employee benefit plans and certain IRAs that are not considered part of an employee benefit plan from engaging, either directly or indirectly, in specified transactions involving “plan assets” with parties that, with respect to the employee benefit plan, are “parties in interest” under ERISA or “disqualified persons” under the Code with respect to the employee benefit plan or IRA, unless an exemption is applicable. A party in interest or disqualified person who engaged in a non-exempt prohibited transaction may be subject to excise taxes and other penalties and liabilities under ERISA and the Code. In addition, the fiduciary of the ERISA plan that engaged in such non-exempt prohibited transaction may be subject to excise taxes, penalties and liabilities under ERISA and the Code.

In addition to considering whether the purchase of our common units is a prohibited transaction, a fiduciary of an employee benefit plan should consider whether the employee benefit plan will, by investing in our common units, be deemed to own an undivided interest in our assets, with the result that our general partner also would be a fiduciary of the plan and our operations would be subject to the regulatory restrictions of ERISA, including its

Index to Financial Statements

prohibited transaction rules, as well as the prohibited transaction rules of ERISA, the Code and any other applicable Similar Laws.

The U.S. Department of Labor regulations and Section 3(42) of ERISA provide guidance with respect to whether, in certain circumstances, the assets of an entity in which employee benefit plans acquire equity interests would be deemed “plan assets” under certain circumstances. Under these rules, an entity’s underlying assets generally would not be considered to be “plan assets” if, among other things:

With respect to an investment in our common units, we believe that our assets should not be considered “plan assets” under these regulations because it is expected that the investment will satisfy the requirements in (a) and (b) above and may also satisfy the requirements in (c) above (although we do not monitor the level of investment by benefit plan investors as required for compliance with (c)).

The foregoing discussion of issues arising for employee benefit plan investments under ERISA, the Code and applicable Similar Laws is general in nature and is not intended to be all inclusive, nor should it be construed as legal advice. In light of the serious penalties imposed on persons who engage in prohibited transactions or other violations, plan fiduciaries contemplating a purchase of our common units should consult with their own counsel regarding the consequences of such purchase under ERISA, the Code and other Similar Laws.

Index to Financial Statements

Under the terms and subject to the conditions in an underwriting agreement dated the date of this prospectus, the underwriters named below, for whom Morgan Stanley & Co. LLC, are acting as representatives, have severally agreed to purchase, and we have agreed to sell to them, severally, the number of common units indicated below:

The underwriters and the representatives are collectively referred to as the “underwriters” and the “representatives,” respectively. The underwriters are offering the common units subject to their acceptance of the common units from us and subject to prior sale. The underwriting agreement provides that the obligations of the several underwriters to pay for and accept delivery of the common units offered by this prospectus are subject to the approval of certain legal matters by their counsel and to certain other conditions. The underwriters are obligated to take and pay for all of the common units offered by this prospectus if any such common units are taken. However, the underwriters are not required to take or pay for the common units covered by the underwriters’ option to purchase additional common units described below. The offering of the units by the underwriters is subject to receipt and acceptance and subject to the underwriters’ right to reject any order in whole or in part.

The underwriters initially propose to offer part of the common units directly to the public at the offering price listed on the cover page of this prospectus and part to certain dealers at a price that represents a concession not in excess of $ per unit under the public offering price. After the initial offering of the common units, the offering price and other selling terms may from time to time be varied by the representatives.

We have granted to the underwriters an option, exercisable for 30 days from the date of this prospectus, to purchase up to additional common units at the public offering price listed on the cover page of this

Index to Financial Statements

prospectus, less underwriting discounts and commissions. To the extent the option is exercised, each underwriter will become obligated, subject to certain conditions, to purchase the same percentage of the additional common units as the number listed next to the underwriter’s name in the preceding table bears to the total number of common units listed next to the names of all underwriters in the preceding table.

The following table shows the per unit and total public offering price, underwriting discounts and commissions, and proceeds before expenses to us. These amounts are shown assuming both no exercise and full exercise of the underwriters’ option to purchase up to an additional common units.

The estimated offering expenses payable by us, exclusive of the underwriting discounts and commissions, are approximately $ . We have agreed to reimburse the underwriters for expense relating to clearance of this offering with the Financial Industry Regulatory Authority up to $ . ZB, N.A. dba Amegy Bank, a lender under Oasis’s revolving credit facility, has acted as a financial advisor to us in connection with this offering and not as an underwriter, and it will receive a fee in connection herewith.

The underwriters have informed us that they do not intend sales to discretionary accounts to exceed 5% of the total number of common units offered by them.

Our common units have been approved for listing on the New York Stock Exchange under the trading symbol “OMP.”

We, Oasis, our general partner, our directors and officers and certain of the other holders of our outstanding common units have agreed that, without the prior written consent of Morgan Stanley & Co. LLC, on behalf of the underwriters, we and they will not, during the period ending 180 days after the date of this prospectus (the “restricted period”):

whether any such transaction described above is to be settled by delivery of common units or such other securities, in cash or otherwise. In addition, we and each such person agrees that, without the prior written consent of Morgan Stanley & Co. LLC, on behalf of the underwriters, we or such other person will not, during the restricted period, make any demand for, or exercise any right with respect to, the registration of any common units or any security convertible into or exercisable or exchangeable for common units.

The restrictions described in the immediately preceding paragraph do not apply to:

Index to Financial Statements

Morgan Stanley & Co. LLC, in its sole discretion, may release the common units and other securities subject to the lock-up agreements described above in whole or in part at any time.

In order to facilitate the offering of the common units, the underwriters may engage in transactions that stabilize, maintain or otherwise affect the price of the common units. Specifically, the underwriters may sell more common units than they are obligated to purchase under the underwriting agreement, creating a short position. A short sale is covered if the short position is no greater than the number of common units available for purchase by the underwriters under the option to purchase additional common units. The underwriters can close out a covered short sale by exercising the option to purchase additional common units or purchasing common units in the open market. In determining the source of common units to close out a covered short sale, the underwriters will consider, among other things, the open market price of common units compared to the price available under the option to purchase additional common units. The underwriters may also sell common units in excess of the option to purchase additional units, creating a naked short position. The underwriters must close out any naked short position by purchasing common units in the open market. A naked short position is more likely to be created if the underwriters are concerned that there may be downward pressure on the price of the common units in the open market after pricing that could adversely affect investors who purchase in this offering. As an additional means of facilitating this offering, the underwriters may bid for, and purchase, common units in the open market to stabilize the price of the common units. These activities may raise or maintain the market price of the common units above independent market levels or prevent or retard a decline in the market price of the common units. The underwriters are not required to engage in these activities and may end any of these activities at any time.

We and the underwriters have agreed to indemnify each other against certain liabilities, including liabilities under the Securities Act.

A prospectus in electronic format may be made available on websites maintained by one or more underwriters participating in this offering. The representatives may agree to allocate a number of common units to underwriters for sale to their online brokerage account holders. Internet distributions will be allocated by the representatives to underwriters that may make Internet distributions on the same basis as other allocations.

The underwriters and their respective affiliates are full service financial institutions engaged in various activities, which may include securities trading, commercial and investment banking, financial advisory, investment management, investment research, principal investment, hedging, financing and brokerage activities. Certain of the underwriters and their respective affiliates have, from time to time, performed, and may in the future perform, various financial advisory and investment banking services for us or our affiliates, for which they received or will receive customary fees and expenses. Certain of the underwriters and their respective affiliates will be lenders under our new revolving credit facility and are lenders under Oasis’s revolving credit facility.

Index to Financial Statements

In addition, in the ordinary course of their various business activities, the underwriters and their respective affiliates may make or hold a broad array of investments and actively trade debt and equity securities (or related derivative securities) and financial instruments (including bank loans) for their own account and for the accounts of their customers and may at any time hold long and short positions in such securities and instruments. Such investment and securities activities may involve our securities and instruments. The underwriters and their respective affiliates may also make investment recommendations or publish or express independent research views in respect of such securities or instruments and may at any time hold, or recommend to clients that they acquire, long or short positions in such securities and instruments.

Prior to this offering, there has been no public market for our common units. The initial public offering price was determined by negotiations between us and the representatives. Among the factors considered in determining the initial public offering price were our future prospects and those of our industry in general, our sales, earnings and certain other financial and operating information in recent periods, and the price-earnings ratios, price-sales ratios, market prices of securities, and certain financial and operating information of companies engaged in activities similar to ours.

At our request, the underwriters have reserved % of the common units offered by this prospectus for sale, at the initial public offering price, to directors, officers, employees and certain other persons associated with us. If purchased by these persons, these common units will be subject to a 180-day lock-up restriction. The number of common units available for sale to the general public will be reduced to the extent these individuals purchase such reserved common units. Any reserved common units that are not so purchased will be offered by the underwriters to the general public on the same basis as the other common units offered by this prospectus.

In relation to each Member State of the European Economic Area which has implemented the Prospectus Directive (each, a “Relevant Member State”) an offer to the public of any of our common units may not be made in that Relevant Member State, except that an offer to the public in that Relevant Member State of any common units may be made at any time under the following exemptions under the Prospectus Directive, if they have been implemented in that Relevant Member State:

(a) to any legal entity which is a qualified investor as defined in the Prospectus Directive;

(b) to fewer than 100 or, if the Relevant Member State has implemented the relevant provision of the 2010 PD Amending Directive, 150, natural or legal persons (other than qualified investors as defined in the Prospectus Directive), as permitted under the Prospectus Directive, subject to obtaining the prior consent of the representatives for any such offer; or

(c) in any other circumstances falling within Article 3(2) of the Prospectus Directive, provided that no such offer of common units shall result in a requirement for the publication by us or any underwriter of a prospectus pursuant to Article 3 of the Prospectus Directive.

For the purposes of this provision, the expression an “offer to the public” in relation to any common units in any Relevant Member State means the communication in any form and by any means of sufficient information on the terms of the offer and any common units to be offered so as to enable an investor to decide to purchase any common units, as the same may be varied in that Member State by any measure implementing the Prospectus

Index to Financial Statements

Directive in that Member State, the expression “Prospectus Directive” means Directive 2003/71/EC (and amendments thereto, including the 2010 PD Amending Directive, to the extent implemented in the Relevant Member State), and includes any relevant implementing measure in the Relevant Member State, and the expression “2010 PD Amending Directive” means Directive 2010/73/EU.

(a) it has only communicated or caused to be communicated and will only communicate or cause to be communicated an invitation or inducement to engage in investment activity (within the meaning of Section 21 of the Financial Services and Markets Act 2000 (“FSMA”) received by it in connection with the issue or sale of our common units in circumstances in which Section 21(1) of the FSMA does not apply to us; and

(b) it has complied and will comply with all applicable provisions of the FSMA with respect to anything done by it in relation to our common units in, from or otherwise involving the United Kingdom.

This document has not been prepared in accordance with the requirements for a securities or sales prospectus under the German Securities Prospectus Act (Wertpapierprospektgesetz), the German Sales Prospectus Act (Verkaufsprospektgesetz), or the German Investment Act (Investmentgesetz). Neither the German Federal Financial Services Supervisory Authority (Bundesanstalt für Finanzdienstleistungsaufsicht—BaFin) nor any other German authority has been notified of the intention to distribute our common units in Germany. Consequently, our common units may not be distributed in Germany by way of public offering, public advertisement or in any similar manner and this document and any other document relating to the offering, as well as information or statements contained therein, may not be supplied to the public in Germany or used in connection with any offer for subscription of our common units to the public in Germany or any other means of public marketing. Our common units are being offered and sold in Germany only to qualified investors which are referred to in Section 3, paragraph 2 no. 1, in connection with Section 2, no. 6, of the German Securities Prospectus Act, Section 8f paragraph 2 no. 4 of the German Sales Prospectus Act, and in Section 2 paragraph 11 sentence 2 no. 1 of the German Investment Act. This document is strictly for use of the person who has received it. It may not be forwarded to other persons or published in Germany.

The offering does not constitute an offer to sell or the solicitation of an offer to buy our common units in any circumstances in which such offer or solicitation is unlawful.

Our common units may not be offered or sold, directly or indirectly, in the Netherlands, other than to qualified investors (gekwalificeerde beleggers) within the meaning of Article 1:1 of the Dutch Financial Supervision Act (Wet op het financieel toezicht).

Neither this prospectus nor any other offering material relating to the common units described in this prospectus has been submitted to the clearance procedures of the Autorite des Marches Financiers or of the competent authority of another member state of the European Economic Area and notified to the Autorite des Marches Financiers. The common units have not been offered or sold and will not be offered or sold, directly or indirectly, to the public in France. Neither this prospectus nor any other offering material relating to the common units has been or will be:

Index to Financial Statements

The common units may be resold directly or indirectly, only in compliance with articles L.411-1, L.411-2, L.412-1 and L.621-8 through L.621-8-3 of the French Code monetaire et financier.

We have not been registered with the Swiss Financial Market Supervisory Authority FINMA as a foreign collective investment scheme pursuant to Article 120 of the Collective Investment Schemes Act of June 23, 2006 (CISA). Accordingly, our common units may not be offered to the public in or from Switzerland, and neither this prospectus nor any other offering materials relating to our common units may be made available through a public offering in or from Switzerland. Our common units may only be offered and this prospectus may only be distributed in or from Switzerland by way of private placement exclusively to qualified investors (as this term is defined in the CISA and its implementing ordinance).

No placement document, prospectus, product disclosure statement or other disclosure document has been lodged with the Australian Securities and Investments Commission, in relation to the offering. This prospectus does not constitute a prospectus, product disclosure statement or other disclosure document under the Corporations Act 2001 (the “Corporations Act”), and does not purport to include the information required for a prospectus, product disclosure statement or other disclosure document under the Corporations Act.

Any offer in Australia of the common units may only be made to persons (the “Exempt Investors”), who are:

(a) “sophisticated investors” (within the meaning of section 708(8) of the Corporations Act), “professional investors” (within the meaning of Section 708(11) of the Corporations Act) or otherwise pursuant to one or more exemptions contained in Section 708 of the Corporations Act; and

(b) “wholesale clients” (within the meaning of Section 761G of the Corporations Act);

so that it is lawful to offer the common units without disclosure to investors under Chapters 6D and 7 of the Corporations Act.

The common units applied for by Exempt Investors in Australia must not be offered for sale in Australia in the period of 12 months after the date of allotment under the offering, except in circumstances where disclosure to investors under Chapters 6D and 7 of the Corporations Act would not be required pursuant to an exemption under both Section 708 and Subdivision B of Division 2 of Part 7.9 of the Corporations Act or otherwise or where the offer is pursuant to a disclosure document which complies with Chapters 6D and 7 of the Corporations Act. Any person acquiring common units must observe such Australian on-sale restrictions.

Index to Financial Statements

This prospectus contains general information only and does not take account of the investment objectives, financial situation or particular needs of any particular person. It does not contain any securities recommendations or financial product advice. Before making an investment decision, investors need to consider whether the information in this prospectus is appropriate to their needs, objectives and circumstances, and, if necessary, seek expert advice on those matters.

The units may be sold only to purchasers purchasing, or deemed to be purchasing, as principal that are accredited investors, as defined in National Instrument 45-106 Prospectus Exemptions or subsection 73.3(1) of the Securities Act (Ontario), and are permitted clients, as defined in National Instrument 31-103 Registration Requirements, Exemptions and Ongoing Registrant Obligations. Any resale of the units must be made in accordance with an exemption from, or in a transaction not subject to, the prospectus requirements of applicable securities laws.

Securities legislation in certain provinces or territories of Canada may provide a purchaser with remedies for rescission or damages if this prospectus (including any amendment thereto) contains a misrepresentation, provided that the remedies for rescission or damages are exercised by the purchaser within the time limit prescribed by the securities legislation of the purchaser’s province or territory. The purchaser should refer to any applicable provisions of the securities legislation of the purchaser’s province or territory for particulars of these rights or consult with a legal advisor.

Pursuant to section 3A.3 (or, in the case of securities issued or guaranteed by the government of a non-Canadian jurisdiction, section 3A.4) of National Instrument 33-105 Underwriting Conflicts (NI 33-105), the underwriters are not required to comply with the disclosure requirements of NI 33-105 regarding underwriter conflicts of interest in connection with this offering.

The common units have not been and will not be offered or sold in Hong Kong, by means of any document, other than (a) to “professional investors” as defined in the Securities and Futures Ordinance (Cap. 571) of Hong Kong and any rules made under that Ordinance; or (b) in other circumstances which do not result in the document being a “prospectus” as defined in the Companies Ordinance (Cap. 32) of Hong Kong or which do not constitute an offer to the public within the meaning of that Ordinance. No advertisement, invitation or document relating to the common units has been or may be issued or has been or may be in the possession of any person for the purposes of issue, whether in Hong Kong or elsewhere, which is directed at, or the contents of which are likely to be accessed or read by, the public of Hong Kong (except if permitted to do so under the securities laws of Hong Kong) other than with respect to common units which are or are intended to be disposed of only to persons outside Hong Kong or only to “professional investors” as defined in the Securities and Futures Ordinance and any rules made under that Ordinance.

This prospectus has not been registered as a prospectus with the Monetary Authority of Singapore. Accordingly, this prospectus and any other document or material in connection with the offer or sale, or invitation for subscription or purchase, of the common units may not be circulated or distributed, nor may the common units be offered or sold, or be made the subject of an invitation for subscription or purchase, whether directly or indirectly, to persons in Singapore other than (i) to an institutional investor (as defined under Section 4A of the Securities and Futures Act, Chapter 289 of Singapore (the “SFA”)) under Section 274 of the SFA, (ii) to a relevant person (as defined in Section 275(2) of the SFA) pursuant to Section 275(1) of the SFA, or any person pursuant to Section 275(1A) of the SFA, and in accordance with the conditions specified in Section 275 of the SFA or (iii) otherwise pursuant to, and in accordance with the conditions of, any other applicable provision of the SFA, in each case subject to conditions set forth in the SFA.

Index to Financial Statements

Where the common units are subscribed or purchased under Section 275 of the SFA by a relevant person which is a corporation (which is not an accredited investor (as defined in Section 4A of the SFA)) the sole business of which is to hold investments and the entire unit capital of which is owned by one or more individuals, each of whom is an accredited investor, the securities (as defined in Section 239(1) of the SFA) of that corporation shall not be transferable for 6 months after that corporation has acquired the common units under Section 275 of the SFA except: (1) to an institutional investor under Section 274 of the SFA or to a relevant person (as defined in Section 275(2) of the SFA), (2) where such transfer arises from an offer in that corporation’s securities pursuant to Section 275(1A) of the SFA, (3) where no consideration is or will be given for the transfer, (4) where the transfer is by operation of law, (5) as specified in Section 276(7) of the SFA, or (6) as specified in Regulation 32 of the Securities and Futures (Offers of Investments) (Units and Debentures) Regulations 2005 of Singapore (“Regulation 32”).

Where the common units are subscribed or purchased under Section 275 of the SFA by a relevant person which is a trust (where the trustee is not an accredited investor (as defined in Section 4A of the SFA)) whose sole purpose is to hold investments and each beneficiary of the trust is an accredited investor, the beneficiaries’ rights and interest (howsoever described) in that trust shall not be transferable for six months after that trust has acquired the common units under Section 275 of the SFA except: (1) to an institutional investor under Section 274 of the SFA or to a relevant person (as defined in Section 275(2) of the SFA), (2) where such transfer arises from an offer that is made on terms that such rights or interest are acquired at a consideration of not less than S$200,000 (or its equivalent in a foreign currency) for each transaction (whether such amount is to be paid for in cash or by exchange of securities or other assets), (3) where no consideration is or will be given for the transfer, (4) where the transfer is by operation of law, (5) as specified in Section 276(7) of the SFA, or (6) as specified in Regulation 32.

No registration pursuant to Article 4, paragraph 1 of the Financial Instruments and Exchange Law of Japan (Law No. 25 of 1948, as amended) (the “FIEL”) has been made or will be made with respect to the solicitation of the application for the acquisition of the shares of common stock.

Accordingly, the shares of common stock have not been, directly or indirectly, offered or sold and will not be, directly or indirectly, offered or sold in Japan or to, or for the benefit of, any resident of Japan (which term as used herein means any person resident in Japan, including any corporation or other entity organized under the laws of Japan) or to others for re-offering or re-sale, directly or indirectly, in Japan or to, or for the benefit of, any resident of Japan except pursuant to an exemption from the registration requirements, and otherwise in compliance with, the FIEL and the other applicable laws and regulations of Japan.

Please note that the solicitation for newly-issued or secondary securities (each as described in Paragraph 2, Article 4 of the FIEL) in relation to the shares of common stock constitutes either a “QII only private placement” or a “QII only secondary distribution” (each as described in Paragraph 1, Article 23-13 of the FIEL). Disclosure regarding any such solicitation, as is otherwise prescribed in Paragraph 1, Article 4 of the FIEL, has not been made in relation to the shares of common stock. The shares of common stock may only be transferred to QIIs.

Please note that the solicitation for newly-issued or secondary securities (each as described in Paragraph 2, Article 4 of the FIEL) in relation to the shares of common stock constitutes either a “small number private placement” or a “small number private secondary distribution” (each as is described in Paragraph 4, Article 23-13 of the FIEL). Disclosure regarding any such solicitation, as is otherwise prescribed in Paragraph 1, Article 4 of the FIEL, has not been made in relation to the shares of common stock. The shares of common stock may only be transferred en bloc without subdivision to a single investor.

Index to Financial Statements

This prospectus relates to an exempt offer in accordance with the Offered Securities Rules of the Dubai Financial Services Authority. This document is intended for distribution only to persons of a type specified in those rules. It must not be delivered to, or relied on by, any other person. The Dubai Financial Services Authority has no responsibility for reviewing or verifying any documents in connection with exempt offers. The Dubai Financial Services Authority has not approved this prospectus nor taken steps to verify the information set out herein, and has no responsibility for this prospectus. The common units which are the subject of the offering contemplated by this prospectus may be illiquid and/or subject to restrictions on their resale.

Prospective purchasers of the common units offered should conduct their own due diligence on the common units. If you do not understand the contents of this document you should consult an authorized financial adviser.

Index to Financial Statements

The validity of our common units offered by this prospectus will be passed upon for us by Vinson & Elkins L.L.P., Houston, Texas. Certain legal matters in connection with our common units offered hereby will be passed upon for the underwriters by Kirkland & Ellis LLP, Houston, Texas.

The financial statements of Oasis Midstream Partners LP Predecessor as of December 31, 2016 and December 31, 2015, and for each of the two years in the period ended December 31, 2016, included in this prospectus, have been so included in reliance on the report (which contains an explanatory paragraph relating to the Company’s significant transactions and relationships with affiliated entities, Oasis Petroleum Inc. and Oasis Petroleum North America LLC as described in Note 3 to the financial statements) of PricewaterhouseCoopers LLP, an independent registered public accounting firm, given on the authority of said firm as experts in auditing and accounting.

The balance sheets of Oasis Midstream Partners LP as of December 31, 2016 and 2015, included in this prospectus, have been so included in reliance on the report of PricewaterhouseCoopers LLP, an independent registered public accounting firm, given on the authority of said firm as experts in auditing and accounting.

We have filed with the SEC a registration statement on Form S-1 (including the exhibits, schedules and amendments thereto) under the Securities Act with respect to our common units offered hereby. This prospectus does not contain all of the information set forth in the registration statement and the exhibits and schedules thereto. For further information regarding us and our common units offered hereby, we refer you to the registration statement and the exhibits and schedules filed therewith. Statements contained in this prospectus as to the contents of any contract, agreement or any other document are summaries of the material terms of such contract, agreement or other document and are not necessarily complete. With respect to each of these contracts, agreements or other documents filed as an exhibit to the registration statement, reference is made to the exhibits for a more complete description of the matter involved. A copy of the registration statement, and the exhibits and schedules thereto, may be inspected without charge at the public reference facilities maintained by the SEC at 100 F Street NE, Washington, D.C. 20549. Copies of these materials may be obtained, upon payment of a duplicating fee, from the Public Reference Room of the SEC at 100 F Street NE, Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the operation of the Public Reference Room. The SEC maintains a website that contains reports, proxy and information statements and other information regarding registrants that file electronically with the SEC. The address of the SEC’s website is www.sec.gov.

As a result of this offering, we will become subject to the reporting requirements of the Exchange Act. We will fulfill our obligations with respect to such requirements by filing periodic reports and other information with the SEC. We intend to furnish our unitholders with annual reports containing financial statements certified by an independent public accounting firm.

Index to Financial Statements

Set forth below are the unaudited pro forma condensed balance sheet of Oasis Midstream Partners LP (the “Partnership”) as of March 31, 2017 and the unaudited pro forma condensed statement of operations of the Partnership for the year ended December 31, 2016 and for the three months ended March 31, 2017. The pro forma financial data of the Partnership has been derived by adjusting the historical financial statements of Oasis Midstream Services LLC (“OMS” or the “Predecessor”).

The Predecessor’s business included the assets, liabilities and results of operations contributed to the three development companies, Bighorn DevCo, Bobcat DevCo and Beartooth DevCo (collectively, the “DevCos”), which will be controlled by the Partnership. Both Bighorn DevCo and Bobcat DevCo have assets and operations in the Wild Basin operating area. Bighorn DevCo’s assets include gas processing and crude oil stabilization, blending, storage and transportation. Bobcat DevCo’s assets include gas gathering, compression and gas lift, crude oil gathering and produced water gathering and disposal. Beartooth DevCo owns water infrastructure assets, which deliver freshwater for well completion as well as gather and dispose produced water and are predominately located in Oasis’s Alger, Cottonwood, Hebron, Indian Hills and Red Bank operating areas. Upon completion of this offering, the Partnership will own controlling interests in the DevCos that own the contributed assets. The Partnership has recorded the contribution of the contributed assets at historical cost, as the contribution will be considered a reorganization of entities under common control.

The historical financial statements of the Predecessor are set forth elsewhere in this prospectus, and the pro forma financial data of the Partnership should be read in conjunction with, and are qualified in their entirety by reference to, such historical financial statements and the related notes contained herein. The pro forma adjustments are based on currently available information and certain estimates and assumptions, and actual results may differ from the pro forma adjustments. However, management believes that these estimates and assumptions provide a reasonable basis for presenting effects directly attributable to the contemplated transactions and that the pro forma adjustments are factually supportable and give appropriate effect to those estimates and assumptions and are properly applied in the pro forma financial data.

The pro forma adjustments have been prepared as if the transactions to be effected at the closing of this offering had taken place on March 31, 2017, in the case of the unaudited pro forma condensed balance sheet. The unaudited pro forma condensed statement of operations for the year ended December 31, 2016 and for the three months ended March 31, 2017 has been prepared as if the transactions to be effected at closing of the offering had taken place on January 1, 2016. The unaudited pro forma condensed financial statements have been prepared on the assumption that the Partnership will be treated as a partnership for United States federal income tax purposes.

The unaudited pro forma condensed financial statements give pro forma effect to the matters described in the notes hereto, including:

Index to Financial Statements

For the purposes of the unaudited pro forma condensed financial statements, the Partnership has assumed that the underwriters’ option to purchase additional common units is not exercised. The unaudited pro forma condensed financial statements do not give effect to the estimated $2.5 million in incremental annual general and administrative expenses that the Partnership expects to incur as a result of being a publicly traded partnership.

In connection with the closing of this offering, the Partnership expects to enter into a new year, $ million revolving credit facility to fund working capital, acquisitions, distributions and capital expenditures and for other general partnership purposes. The Partnership will incur interest expense on any outstanding borrowings under the revolving credit facility, will pay a commitment fee for the unutilized portion of the revolving credit facility and will amortize the debt issuance costs incurred in connection with the credit facility over the term of the revolving credit facility.

The unaudited pro forma condensed financial statements may not be indicative of the results that actually would have occurred if the Partnership had assumed the operations of the Predecessor on the dates indicated or that will be obtained in the future.

Index to Financial Statements

The accompanying notes are an integral part of these unaudited pro forma condensed financial statements.

Index to Financial Statements

The accompanying notes are an integral part of these unaudited pro forma condensed financial statements.

Index to Financial Statements

The accompanying notes are an integral part of these unaudited pro forma condensed financial statements.

Index to Financial Statements

The unaudited pro forma condensed balance sheet as of March 31, 2017 and the unaudited pro forma condensed statement of operations of the Partnership for the three months ended March 31, 2017 and for the year ended December 31, 2016 are based upon the historical unaudited condensed financial statements and audited financial statements of the Predecessor, respectively.

The following adjustments for the Partnership have been prepared as if the Partnership’s initial public offering and related transactions had taken place at January 1, 2016 in the case of the unaudited pro forma condensed statement of operations and on March 31, 2017 in the case of the unaudited pro forma condensed balance sheet. The adjustments are based on currently available information and certain estimates and assumptions and therefore the actual effects of those transactions will differ from the pro forma adjustments. A general description of these transactions and adjustments is provided as follows:

(a) Reflects the net adjustments to cash and cash equivalents, as follows (in thousands):

(b) Reflects the removal of certain assets, liabilities, revenues and expenses that will be excluded from the businesses of the DevCos upon formation. The inclusion of these assets in the Predecessor’s historical financial statements resulted in additional revenues and general and administrative (“G&A”) expenses of $12.1 million and $0.7 million, respectively, for the year ended December 31, 2016, and $1.1 million and $0.1 million, respectively, for the three months ended March 31, 2017.

(c) Reflects the capitalization of origination fees related to the new revolving credit facility. These costs are deferred and amortized over the term of the credit agreement.

(d) Reflects the removal of historical income taxes as the Partnership will not be subject to income taxes following this offering and, therefore, the future financial statements will exclude income tax expense, income taxes payable and deferred tax accounts.

(e) Reflects net adjustments to the public common unitholders’ partners’ capital, as follows (in thousands):

(f) Reflects the elimination of Oasis’s net investment in the Predecessor after giving effect to Oasis’s contribution to the Partnership of 100%, 10% and 35% controlling interests in Bighorn DevCo, Bobcat DevCo and Beartooth DevCo, respectively. The adjustment also represents the distribution of the remaining IPO

Index to Financial Statements

proceeds of $ million to Oasis. The following table provides a reconciliation of pro forma partners’ capital to the controlling interests and non-controlling interests.

(g) Reflects the pro forma adjustment to revenues of $15.9 million associated with certain rate changes related to the Partnership’s execution of long-term, fixed-fee commercial agreements with Oasis. The decrease to revenue is calculated using the amended fees under the commercial agreements applied to the historical volumes for the period January 1, 2016 through September 30, 2016. No pro forma adjustment for the period October 1, 2016 through December 31, 2016 was necessary as fees were consistent with the commercial agreements.

(h) Following the closing of this offering, under the services and secondment agreement, Oasis will continue to charge the Partnership a combination of direct and indirect allocated charges for G&A services. The Partnership also currently anticipates incurring approximately $2.5 million of incremental G&A expenses attributable to operating as a publicly traded partnership. The unaudited pro forma condensed financial statements do not reflect these incremental public company costs. For more information about such fees and services, please read “Certain Relationships and Related Party Transactions—Agreements with Affiliates in Connection with the Transactions—Services and Secondment Agreement.”

(i) Reflects the removal of $5.5 million and $1.2 million for the year ended December 31, 2016 and the three months ended March 31, 2017, respectively, associated with the Predecessor’s allocated portion of Oasis’s interest expense and the addition of $0.4 million and $0.1 million related to the amortization of origination fees and $0.8 million and $0.2 million for commitment fees associated with the new revolving credit facility over the year expected term of the facility for the year ended December 31, 2016 and the three months ended March 31, 2017, respectively.

Index to Financial Statements

(j) Reflects 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. The following table provides a reconciliation of pro forma net income attributable to controlling interests and net income attributable to non-controlling interests.

Pro forma net income per unit is determined by dividing pro forma net income that would have been allocated, in accordance with the net income and loss allocation provisions of the partnership agreement, to the common and subordinated unitholders under the two-class method by the number of common units and subordinated units expected to be outstanding at the completion of this offering. For purposes of this calculation, it was assumed that (1) the minimum quarterly distribution was made to all unitholders for each quarter during the periods presented and (2) the number of units outstanding was common units and subordinated units. The common and subordinated unitholders represent an aggregate 100% limited partner interest in the Partnership. All units were assumed to have been outstanding since January 1, 2016. Basic and diluted pro forma net income per unit are equivalent as there are no dilutive units at the date of closing of the initial public offering of the common units of the Partnership. Pursuant to the partnership agreement, to the extent that the quarterly distributions exceed certain target levels, the general partner is entitled to receive certain incentive distributions that will result in more net income proportionately being allocated to the general partner than to the holders of common units and subordinated units. The pro forma net income per unit calculations assume that no incentive distributions were made to the general partner because no such distributions would have been paid based upon on the assumption that distributions declared equal the minimum quarterly distribution.

Index to Financial Statements

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

Index to Financial Statements

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

Index to Financial Statements

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

Index to Financial Statements

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

Index to Financial Statements

Oasis Midstream Partners LP Predecessor (the “Predecessor”) includes all of the assets, liabilities and results of operations of Oasis Midstream Services LLC (“OMS”), prior to the formation of Oasis Midstream Partners LP (the “Partnership”), an indirect wholly owned subsidiary of Oasis Petroleum Inc. (together with its subsidiaries, “Oasis” or the “Parent”), in connection with the Partnership’s proposed initial public offering. OMS was formed in 2013 as a Delaware limited liability company and wholly owned subsidiary of Oasis to provide midstream infrastructure services to Oasis Petroleum North America LLC (“OPNA”), a wholly owned subsidiary of Oasis that conducts its domestic oil and natural gas exploration and production (“E&P”) activities, and to third parties operated in and around OMS’s assets. OMS was operated by Oasis during the periods presented in the accompanying financial statements.

Oasis is an independent E&P company focused on the acquisition and development of unconventional oil and natural gas resources in the Williston Basin. Oasis’s proved and unproved oil and natural gas properties are located in the North Dakota and Montana areas of the Williston Basin and are owned by OPNA. OMS performs natural gas services (gathering, compression, processing and gas lift), crude oil services (gathering, stabilization, blending, storage and transportation), produced and flowback water services (gathering and disposal), freshwater services (fracwater and flushwater distribution) and other midstream services primarily for certain oil and natural gas wells operated by OPNA. OMS owns and operates a natural gas processing plant, centralized gas lift system, crude stabilization, blending and storage system, a FERC-regulated crude transportation pipeline, saltwater disposal (“SWD”) wells, produced water, natural gas and crude oil gathering pipelines and freshwater distribution pipelines.

The accompanying condensed financial statements and related notes present the financial position, results of operations, cash flows and net parent investment of the Predecessor. These condensed financial statements include financial data at Oasis’s historical cost and have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). The Predecessor includes 100% of the operations of OMS, reflecting the historical ownership of this business segment by Oasis. OMS has no intercompany transactions and substantially all services are provided to OPNA.

These interim financial statements have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”) regarding interim financial reporting. Certain disclosures have been condensed or omitted from these financial statements. Accordingly, they do not include all of the information and notes required by GAAP for complete financial statements and should be read in conjunction with the audited financial statements and notes thereto included in elsewhere in this prospectus. In the opinion of management, all adjustments, consisting of normal recurring adjustments necessary for the fair statement, have been included. Operating results for the three months ended March 31, 2017 are not necessarily indicative of the results that may be expected for the year ending December 31, 2017.

SEC Staff Accounting Bulletin 1.B.3 requires that certain distributions to owners prior to or concurrent with an initial public offering be considered as distributions in contemplation of that offering. Upon completion of the

Index to Financial Statements

Partnership’s proposed initial public offering, the Partnership intends to distribute approximately $ million to Oasis. The supplemental pro forma balance sheet as of March 31, 2017 gives pro forma effect to this assumed distribution as though it had been declared and was payable as of that date. Unaudited basic and diluted pro forma earnings per common unit for the Predecessor for the three months ended March 31, 2017 assumed subordinated units and common units were outstanding in the period. The common units consist of common units issued to Oasis plus an additional common units, which is the number of common units the Partnership would have been required to issue to fund the $ distribution of net proceeds to Oasis. The number of common units that the Partnership would have been required to issue to fund the $ million distribution was calculated as $ million divided by an issue price per unit of $ , which is the initial public offering price of $ per common unit less the estimated underwriting discounts, structuring fee and offering expenses. There were no potential common units outstanding to be considered in the pro forma diluted earnings per unit calculation.

There have been no material changes to the Predecessor’s critical accounting policies and estimates from those disclosed in Note 2 in the audited financial statements included in elsewhere in this prospectus, other than as noted below.

Stock-based compensation. In the first quarter of 2017, the Predecessor adopted Accounting Standards Update No. 2016-09, Improvements to Employee Share-Based Payment Accounting (“ASU 2016-09”), which updates several aspects of the accounting for share-based payment transactions, including recognition of excess tax benefits and deficiencies, the classification of those excess tax benefits on the statement of cash flows, an accounting policy election for forfeitures, the amount an employer can withhold to cover income taxes and still qualify for equity classification and the classification of those taxes paid on the statement of cash flows. In accordance with the new guidance, the Predecessor recorded a $59,000 cumulative-effect adjustment to retained earnings on the Predecessor’s Condensed Balance Sheet as of March 31, 2017, which included the removal of the estimated forfeiture rate. ASU 2016-09 was applied on a modified retrospective basis and prior periods were not retrospectively adjusted.

Revenue recognition. In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”). The objective of ASU 2014-09 is greater consistency and comparability across industries by using a five-step model to recognize revenue from customer contracts. ASU 2014-09 also contains some new disclosure requirements under GAAP. In August 2015, the FASB issued Accounting Standards Update No. 2015-14, Deferral of the Effective Date (“ASU 2015-14”). ASU 2015-14 defers the effective date of the new revenue standard by one year, making it effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. In 2016, the FASB issued additional accounting standards updates to clarify the implementation guidance of ASU 2014-09. The Predecessor is currently evaluating the effect that adopting this guidance will have on its financial position, cash flows and results of operations.

Leases. In February 2016, the FASB issued Accounting Standards Update No. 2016-02, Leases (“ASU 2016-02”), which requires a lessee to recognize lease payment obligations and a corresponding right-of-use asset to be measured at fair value on the balance sheet. ASU 2016-02 also requires certain qualitative and quantitative disclosures about the amount, timing and uncertainty of cash flows arising from leases. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, including interim periods within those years. The Predecessor is currently evaluating the effect that adopting this guidance will have on its financial position, cash flows and results of operations.

Statement of cash flows. In August 2016, the FASB issued Accounting Standards Update No. 2016-15, Statement of Cash Flows (“ASU 2016-15”), which is intended to reduce diversity in practice in how

Index to Financial Statements

certain transactions are classified in the statement of cash flows. ASU 2016-15 is effective for fiscal years beginning after December 15, 2017, including interim periods within those years. The adoption of this guidance will not impact the Predecessor’s financial position or results of operations but could result in presentation changes on its statement of cash flows.

Business combinations. In January 2017, the FASB issued Accounting Standards Update No. 2017-01, Clarifying the Definition of a Business (“ASU 2017-01”), which provides guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. ASU 2017-01 requires entities to use a screen test to determine when an integrated set of assets and activities is not a business or if the integrated set of assets and activities needs to be further evaluated against the framework. ASU 2017-01 is effective for fiscal years beginning after December 15, 2017, including interim periods within those years. The Predecessor is currently evaluating the effect that adopting this guidance will have on its financial position, cash flows and results of operations.

The Predecessor is part of the consolidated operations of Oasis and substantially all of its revenues are derived from transactions with OPNA.

Oasis also provides substantial labor and overhead support for the Predecessor, and the accompanying financial statements include shared service expense allocations for support functions provided by Oasis. These support functions include direct labor, as well as centralized corporate, general and administrative services, such as legal, corporate recordkeeping, planning, budgeting, regulatory, accounting, billing, business development, treasury, insurance administration and claims processing, risk management, health, safety and environmental, information technology, human resources, investor relations, cash management and banking, payroll, internal audit, taxes and engineering. Allocations are based primarily on headcount and direct usage during the respective years. Management believes that these allocations are reasonable and reflect the utilization of services provided and benefits received, but may differ from the cost that would have been incurred had the Predecessor operated as a stand-alone company for the years presented. For the three months ended March 31, 2017 and 2016, the Predecessor was allocated $2.7 million and $1.9 million, respectively, of general and administrative expenses in its Condensed Statements of Operations.

Additionally, the Predecessor recognized interest expense related to its funding activity with Oasis based on capital expenditures for the period using the weighted average effective interest rate for Oasis’s long term indebtedness. For the three months ended March 31, 2017 and 2016, interest expense, net of capitalized interest, allocated to the Predecessor was $1.2 million and $0.5 million, respectively.

Index to Financial Statements

The following table sets forth the Predecessor’s property, plant and equipment:

In accordance with the FASB’s authoritative guidance on fair value measurements, the Predecessor’s financial assets and liabilities are measured at fair value on a recurring basis. The Predecessor recognizes its non-financial assets and liabilities, such as impaired assets and ARO, at fair value on a non-recurring basis.

As defined in the authoritative guidance, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). To estimate fair value, the Predecessor utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable.

The authoritative guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value, as follows:

Level 1—Unadjusted quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2—Pricing inputs, other than unadjusted quoted prices in active markets included in Level 1, are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument and can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.

Level 3—Pricing inputs are generally less observable from objective sources, requiring internally developed valuation methodologies that result in management’s best estimate of fair value.

Index to Financial Statements

The following table reflects the changes in the Predecessor’s ARO during the three months ended March 31, 2017:

The Predecessor is not a separate taxable entity for U.S. federal and certain states purposes, and its results are included in the consolidated income tax returns of Oasis. The provision for income taxes and income tax assets and liabilities included in the accompanying financial statements were determined as if the Predecessor was a stand-alone taxpayer for all years presented. The Predecessor’s effective tax rate for the three months ended March 31, 2017 and 2016 was 37.3% and 38.9%, respectively.

These effective tax rates were consistent with the statutory tax rate applicable to the U.S. and the blended state rate for the states in which the Predecessor conducts business. As of March 31, 2017, the Predecessor did not have any uncertain tax positions requiring adjustments to its tax liability.

Restricted stock awards. The direct employees of the Predecessor have been granted restricted stock awards by Oasis under its Amended and Restated 2010 Long Term Incentive Plan, which vest over a three-year period. The fair value of restricted stock grants is based on the value of Oasis’s common stock on the date of grant. Compensation expense is recognized ratably over the requisite service period.

During the three months ended March 31, 2017, employees of the Predecessor were granted restricted stock awards equal to 91,300 shares of common stock with a $15.19 weighted average grant date per share value. Stock-based compensation expense recorded for restricted stock awards for the three months ended March 31, 2017 and 2016 was $0.3 million and $0.2 million, respectively, and is included in general and administrative expenses on the Condensed Statements of Operations.

The Predecessor has various contractual obligations in the normal course of its operations. Included below is a discussion of various future commitments of the Predecessor as of March 31, 2017. The commitments under these arrangements are not recorded in the accompanying Condensed Balance Sheets. The amounts disclosed represent undiscounted cash flows, and no inflation elements have been applied. As of March 31, 2017, there have been no material changes to the Predecessor’s future commitments described under “Purchase Agreement,” “Environmental Obligations,” “Parent Senior Unsecured Notes” and “Credit Risk” as disclosed in Note 11 in the audited financial statements included in elsewhere in this prospectus, other than as noted below.

Litigation. The Predecessor is party to various legal and/or regulatory proceedings from time to time arising in the ordinary course of business. When the Predecessor determines that a loss is probable of occurring and is reasonably estimable, the Predecessor accrues an undiscounted liability for such contingencies based on its best estimate using information available at the time. The Predecessor discloses contingencies where an adverse outcome may be material, or in the judgment of management, the matter should otherwise be disclosed.

Index to Financial Statements

Mirada litigation. On March 23, 2017, Mirada Energy, LLC, Mirada Wild Basin Holding Company, LLC and Mirada Energy Fund I, LLC (collectively, “Mirada”) filed a lawsuit against Oasis, OPNA and OMS, seeking monetary damages in excess of $100 million, declaratory relief, attorneys’ fees and costs (Mirada Energy, LLC, et al. v. Oasis Petroleum North America LLC, et al.; in the 334th Judicial District Court of Harris County, Texas; Case Number 2017-19911). Mirada asserts that it is a working interest owner in certain acreage owned and operated by Oasis in Wild Basin. Specifically, Mirada asserts that Oasis has breached certain agreements by: (1) failing to allow Mirada to participate in Oasis’s midstream operations in Wild Basin; (2) refusing to provide Mirada with information that Mirada contends is required under certain agreements and failing to provide information in a timely fashion; (3) failing to consult with Mirada and failing to obtain Mirada’s consent prior to drilling more than one well at a time in Wild Basin; and (4) by overstating the estimated costs of proposed well operations in Wild Basin. Mirada seeks a declaratory judgment that OPNA be removed as operator in Wild Basin at Mirada’s election and that Mirada be allowed to elect a new operator; certain agreements apply to Oasis and Mirada and Wild Basin with respect to this dispute; Oasis be required to provide all information within its possession regarding proposed or ongoing operations in Wild Basin; and OPNA not be permitted to drill, or propose to drill, more than one well at a time in Wild Basin without obtaining Mirada’s consent. Mirada also seeks a declaratory judgment with respect to Oasis’s current midstream operations in Wild Basin. Specifically, Mirada seeks a declaratory judgment that Mirada has a right to participate in Oasis’s Wild Basin midstream operations, consisting of produced water disposal, crude oil gathering and gas gathering and processing; that, upon Mirada’s election to participate, Mirada is obligated to pay its proportionate costs of Oasis’s midstream operations in Wild Basin; and that Mirada would then be entitled to receive a share of revenues from the midstream operations and would not be charged any amount for its use of these facilities for production from the “Contract Area.”

Oasis believes that Mirada’s claims are without merit, that Oasis has complied with its obligations under the applicable agreements and that some of Mirada’s claims are grounded in agreements which do not apply to Oasis. Oasis filed an answer denying Mirada’s claims on April 21, 2017, and intends to vigorously defend against Mirada’s claims and, to the extent the Predecessor is made a party to the suit, the Predecessor intends to vigorously defend itself against such claims. Discovery is ongoing. Trial is currently scheduled for July 2018. However, neither the Predecessor nor Oasis can predict or guarantee the ultimate outcome or resolution of such matter. If such matter were to be determined adversely to the Predecessor’s or Oasis’s interests, or if the Predecessor or Oasis were forced to settle such matter for a significant amount, such resolution or settlement could have a material adverse effect on the Predecessor’s 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 the Predecessor in their current assets and future midstream opportunities and related revenues in Wild Basin.

The Predecessor has evaluated the period after the balance sheet date through May 12, 2017, noting no subsequent events or transactions that required recognition or disclosure in the financial statements.

Index to Financial Statements

In our opinion, the accompanying balance sheets and the related statements of operations, changes in net parent investment and cash flows present fairly, in all material respects, the financial position of Oasis Midstream Partners LP Predecessor (the “Predecessor”) as of December 31, 2016 and 2015, and the results of its operations and its cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Predecessor’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States) and in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 3 to the financial statements, the Predecessor has significant transactions and relationships with affiliated entities, Oasis Petroleum Inc. and Oasis Petroleum North America LLC.

Index to Financial Statements

The accompanying financial statements and related notes present the financial position, results of operations, cash flows and net parent investment of the Predecessor. These financial statements include financial data at Oasis’s historical cost and have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). The Predecessor includes 100% of the operations of OMS, reflecting the historical ownership of this business segment by Oasis. OMS has no intercompany transactions and substantially all services are provided to OPNA.

Staff Accounting Bulletin 1.B.3 requires that certain distributions to owners prior to or concurrent with an initial public offering be considered as distributions in contemplation of that offering. Upon completion of the Partnership’s proposed initial public offering, the Partnership intends to distribute approximately $ million to Oasis. Unaudited basic and diluted pro forma earnings per common unit assumed subordinated units and common units were outstanding for the year ended December 31, 2016. The common units consist of common units retained by Oasis plus an additional common units, which is the number of common units that the Partnership would have been required to issue to fund the $ million distribution to Oasis. The number of common units that the Partnership would have been required to issue to fund the $ million distribution was calculated by dividing the $ million distribution in excess of earnings by an estimated issuance price of $ . There were no potential common units outstanding to be considered in the pro forma diluted earnings per unit calculation.

Index to Financial Statements

Preparation of the Predecessor’s financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to estimates of future development, dismantlement and abandonment costs, estimates relating to certain revenues and expenses and estimates of expenses related to legal, environmental and other contingencies. Certain of these estimates require assumptions regarding future costs and expenses. Actual results could differ from those estimates. Management believes the assumptions underlying the accompanying financial statements, including the assumptions regarding allocation of expenses from Oasis, are reasonable. Nevertheless, the accompanying financial statements may not include all of the expenses that would have been incurred and may not reflect the results of operations, financial position and cash flows had the Predecessor been a stand-alone company during the years presented.

Oasis currently uses a centralized approach to the cash management and financing of its operations. Cash generated by and used in the Predecessor’s operations was transferred to Oasis on a regular basis; therefore, the Predecessor did not have a cash balance as of December 31, 2016 and 2015. The Predecessor has reflected cash management and financing activities performed by Oasis as a component of net parent investment on its accompanying Balance Sheets and as capital contributions from parent on its accompanying Statements of Cash Flows. Additionally, the Predecessor recognizes interest expense related to this funding activity with Oasis based on capital expenditures for the period using the weighted average effective interest rate for Oasis’s long-term indebtedness.

Trade accounts receivable are recorded upon the performance of services to third parties and include costs to be recouped from third parties, such as county taxes. Accounts receivable from Oasis represent the balance due from the performance of services to OPNA. The Predecessor regularly reviews all aged accounts receivable for collectability and establishes an allowance as necessary for individual customer balances. No allowance for doubtful accounts was recorded as of December 31, 2016 and 2015.

An insurance receivable is recorded by crediting and offsetting the original charge. Any differential arising between insurance recoveries and insurance receivables is recorded as a capitalized cost or as an expense, consistent with its original treatment. During the years ended December 31, 2016 and 2015, the Predecessor incurred costs for the remediation of produced water releases that occurred during 2015, and an insurance receivable has been recorded as of December 31, 2016 and 2015 to offset certain remediation costs. The Predecessor expects to continue to record additional costs and recoveries until the insurance claims are fully settled.

Property, plant and equipment is recorded at cost and depreciated on the straight-line method based on 30-year expected lives of the individual assets. The Predecessor’s property, plant and equipment includes SWD facilities, the natural gas processing plant, pipelines, compressor stations, a crude oil terminal and other assets. The calculation for the straight-line depreciation method for SWD facilities takes into consideration estimated future dismantlement, restoration and abandonment costs, which are net of estimated salvage values. The cost of assets disposed of and the associated accumulated depreciation and amortization are removed from the Predecessor’s Balance Sheets with any gain or loss realized upon the sale or disposal included in the Predecessor’s Statements of Operations. Expenditures for maintenance, repairs and minor renewals necessary to

Index to Financial Statements

maintain property and equipment in operating condition are expensed as incurred. Major betterments, replacements and renewals are capitalized to the appropriate property, plant and equipment accounts.

Impairment of Long-Lived Assets. The Predecessor evaluates the ability to recover the carrying amount of long-lived assets and determines whether such long-lived assets have been impaired. Impairment exists when the carrying amount of an asset exceeds estimates of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. When alternative courses of action to recover the carrying amount of a long-lived asset are under consideration, estimates of future undiscounted cash flows take into account possible outcomes and probabilities of their occurrence. If the carrying amount of the long-lived asset is not recoverable, based on the estimated future undiscounted cash flows, the impairment loss is measured as the excess of the asset’s carrying amount over its estimated fair value, such that the asset’s carrying amount is adjusted to its estimated fair value with an offsetting charge to impairment expense.

Fair value represents the estimated price between market participants to sell an asset in the principal or most advantageous market for the asset, based on assumptions a market participant would make. When warranted, management assesses the fair value of long-lived assets using commonly accepted techniques and may use more than one source in making such assessments. Sources used to determine fair value include, but are not limited to, recent third-party comparable sales, internally developed discounted cash flow analyses and analyses from outside advisors. Significant changes, such as changes in contract rates or terms, the condition of an asset or management’s intent to utilize the asset, generally require management to reassess the cash flows related to long-lived assets. A reduction of carrying value of fixed assets would represent a Level 3 fair value measure, as further discussed in Note 7—Fair Value Measurements.

The Predecessor capitalized $4.4 million and $2.9 million of interest costs for the years ended December 31, 2016 and 2015, respectively. These amounts are amortized over the life of the related assets.

Oasis occasionally markets non-core oil and natural gas properties and may include midstream property and equipment owned by the Predecessor in such divestitures. At the end of each reporting period, the Predecessor evaluates the properties being marketed to determine whether any should be reclassified as held for sale. The held for sale criteria includes: management commits to a plan to sell; the asset is available for immediate sale; an active program to locate a buyer exists; the sale of the asset is probable and expected to be completed within one year; the asset is being actively marketed for sale; and it is unlikely that significant changes to the plan will be made. If each of these criteria is met, the property is reclassified as held for sale on the Predecessor’s Balance Sheet and measured at the lower of its carrying amount or estimated fair value less costs to sell. Depreciation and amortization expense is not recorded on assets to be divested once they are classified as held for sale.

In accordance with the Financial Accounting Standard Board’s (“FASB”) authoritative guidance on asset retirement obligations (“ARO”), the Predecessor records the fair value of a liability for a legal obligation to retire an asset in the period in which the liability is incurred with the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. For SWD wells, this is the period in which the well is drilled or acquired. The ARO represents the estimated amount the Predecessor will incur to plug, abandon and remediate the SWD wells at the end of their useful lives, in accordance with applicable state laws. The liability is accreted to its present value each period and the capitalized costs are depreciated using the straight-line method, as discussed above. The accretion expense is recorded as a component of depreciation and amortization in the Predecessor’s Statements of Operations.

Index to Financial Statements

Some of the Predecessor’s assets, including certain pipelines and the natural gas processing plant, have contractual or regulatory obligations to perform remediation and, in some instances, dismantlement and removal activities, when the assets are abandoned. The Predecessor is not able to reasonably estimate the fair value of the asset retirement obligations for these assets because the settlement dates are indeterminable given the expected continued use of the assets with proper maintenance. The Predecessor will record asset retirement obligations for these assets in the periods in which the settlement dates are reasonably determinable.

The Predecessor determines the ARO by calculating the present value of estimated cash flows related to the liability. Estimating the future ARO requires management to make estimates and judgments regarding timing and existence of a liability, as well as what constitutes adequate restoration. Inherent in the fair value calculation are numerous assumptions and judgments including the ultimate costs, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. These assumptions represent Level 3 inputs, as further discussed in Note 7 — Fair Value Measurements. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the related asset.

In the accompanying Balance Sheets, net parent investment represents Oasis’s historical investment in the Predecessor, the Predecessor’s accumulated net results and the net effect of transactions with and contributions from Oasis.

The Predecessor recognizes revenues when delivery has occurred or services have been rendered and collectability is reasonably assured. The Predecessor’s revenues are generated from crude oil gathering and transportation, natural gas gathering and processing, produced water gathering and disposal, freshwater distribution and other midstream services provided by OMS primarily for OPNA’s operated wells. The revenue earned from these services is generally directly related to the volume of crude oil, natural gas and water that flows through its systems.

Environmental expenditures are expensed or capitalized, as appropriate, depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations, and that do not have future economic benefit, are expensed. Liabilities related to future costs are recorded on an undiscounted basis when environmental assessments and/or remediation activities are probable and the costs can be reasonably estimated.

Restricted Stock Awards. The employees of the Predecessor have been granted restricted stock awards by Oasis under its Amended and Restated 2010 Long Term Incentive Plan, which vest over a three-year period. The fair value of restricted stock grants is based on the value of Oasis’s common stock on the date of grant. Compensation expense is recognized ratably over the requisite service period. Oasis assumed annual forfeiture rates by the employee group ranging from 4.6% to 6.3% based on the forfeiture history for this type of award. Stock-based compensation expense recorded for restricted stock awards is included in general and administrative expenses on the Predecessor’s Statements of Operations.

Associated Excess Tax Benefits. Any excess tax benefit arising from the stock-based compensation plan is recognized as a credit to Oasis’s additional paid-in-capital when realized and is calculated as the amount by which the tax benefit related to the tax deduction received exceeds the deferred tax asset associated with the recorded stock-based compensation expense. The excess federal and state tax deduction related to stock-based compensation specific to the Predecessor is included in the net parent investment on the Predecessor’s Balance Sheets.

Index to Financial Statements

The Predecessor’s provision for taxes includes both federal and state taxes. The Predecessor records its federal income taxes in accordance with accounting for income taxes under GAAP which results in the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between the book carrying amounts and the tax basis of assets and liabilities. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized.

The Predecessor applies significant judgment in evaluating its tax positions and estimating its provision for income taxes. During the ordinary course of business, there are many transactions and calculations for which the ultimate tax determination is uncertain. The actual outcome of these future tax consequences could differ significantly from the Predecessor’s estimates, which could impact its financial position, results of operations and cash flows.

The Predecessor also accounts for uncertainty in income taxes recognized in the financial statements in accordance with GAAP by prescribing a recognition threshold and measurement attribute for a tax position taken or expected to be taken in a tax return. Authoritative guidance for accounting for uncertainty in income taxes requires that the Predecessor recognize the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit. For tax positions meeting the more-likely-than-not threshold, the amount recognized in the financial statements is the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax authority. The Predecessor did not have any uncertain tax positions outstanding and, as such, did not record a liability for the years ended December 31, 2016 and 2015.

During the years presented, the Predecessor was wholly owned by Oasis and had no outstanding units. Accordingly, the Predecessor has not presented net income per unit.

Revenue Recognition. In May 2014, the FASB issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”). The objective of ASU 2014-09 is greater consistency and comparability across industries by using a five-step model to recognize revenue from customer contracts. ASU 2014-09 also contains some new disclosure requirements under GAAP. In August 2015, the FASB issued Accounting Standards Update No. 2015-14, Deferral of the Effective Date (“ASU 2015-14”). ASU 2015-14 defers the effective date of the new revenue standard by one year, making it effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. In 2016, the FASB issued additional accounting standards updates to clarify the implementation guidance of ASU 2014-09. The Predecessor is currently evaluating the effect that adopting this guidance will have on its financial position, cash flows and results of operations.

Leases. In February 2016, the FASB issued Accounting Standards Update No. 2016-02, Leases (“ASU 2016-02”), which requires a lessee to recognize lease payment obligations and a corresponding right-of-use asset to be measured at fair value on the balance sheet. ASU 2016-02 also requires certain qualitative and quantitative

Index to Financial Statements

disclosures about the amount, timing and uncertainty of cash flows arising from leases. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, including interim periods within those years. The Predecessor is currently evaluating the effect that adopting this guidance will have on its financial position, cash flows and results of operations.

Stock-Based Compensation. In March 2016, the FASB issued Accounting Standards Update No. 2016-09, Improvements to Employee Share-Based Payment Accounting (“ASU 2016-09”), which updates several aspects of the accounting for share-based payment transactions, including recognition of excess tax benefits and deficiencies, the classification of those excess tax benefits on the statement of cash flows, an accounting policy election for forfeitures, the amount an employer can withhold to cover income taxes and still qualify for equity classification and the classification of those taxes paid on the statement of cash flows. ASU 2016-09 is effective for fiscal years beginning after December 15, 2016, including interim periods within those years. The Predecessor will elect to remove forfeiture rates and record a cumulative-effect adjustment to equity at the beginning of 2017 when the guidance is adopted and does not expect the adoption of this guidance to have a material impact on its cash flows or results of operations.

Statement of Cash Flows. In August 2016, the FASB issued Accounting Standards Update No. 2016-15, Statement of Cash Flows (“ASU 2016-15”), which is intended to reduce diversity in practice in how certain transactions are classified in the statement of cash flows. ASU 2016-15 is effective for fiscal years beginning after December 15, 2017, including interim periods within those years. The adoption of this guidance will not impact the Predecessor’s financial position or results of operations but could result in presentation changes on its statement of cash flows.

Business Combinations. In January 2017, the FASB issued Accounting Standards Update No. 2017-01, Clarifying the Definition of a Business (“ASU 2017-01”), which provides guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. ASU 2017-01 requires entities to use a screen test to determine when an integrated set of assets and activities is not a business or if the integrated set of assets and activities needs to be further evaluated against the framework. ASU 2017-01 is effective for fiscal years beginning after December 15, 2017, including interim periods within those years. The Predecessor is currently evaluating the effect that adopting this guidance will have on its financial position, cash flows and results of operations.

The Predecessor is part of the consolidated operations of Oasis, and substantially all of its revenues are derived from transactions with OPNA.

Oasis also provides substantial labor and overhead support for the Predecessor and the accompanying financial statements include shared service expense allocations for support functions provided by Oasis. These support functions include direct labor, as well as centralized corporate, general and administrative services, such as legal, corporate recordkeeping, planning, budgeting, regulatory, accounting, billing, business development, treasury, insurance administration and claims processing, risk management, health, safety and environmental, information technology, human resources, investor relations, cash management and banking, payroll, internal audit, taxes and engineering. Allocations are based primarily on headcount and direct usage during the respective years. Management believes that these allocations are reasonable and reflect the utilization of services provided and benefits received, but may differ from the cost that would have been incurred had the Predecessor operated as a stand-alone company for the years presented. For the years ended December 31, 2016 and 2015, the Predecessor was allocated $7.8 million and $6.1 million, respectively, of general and administrative expenses in its Statements of Operations.

Index to Financial Statements

indebtedness. For the years ended December 31, 2016 and 2015, interest expense, net of capitalized interest, allocated to the Predecessor was $5.5 million and $4.5 million, respectively.

The following table sets forth the Predecessor’s property, plant and equipment:

Index to Financial Statements

On April 1, 2016, Oasis completed the sale of certain legacy wells that have been producing from conventional reservoirs such as the Madison, Red River and other formations in the Williston Basin other than the Bakken or Three Forks formations (the “2016 Divestiture”). The 2016 Divestiture primarily consisted of OPNA’s oil and gas properties and included certain midstream property and equipment that serviced those wells. There was no gain or loss related to the sale of the midstream assets as the assets were previously adjusted to their sales price, less costs to sell.

Net assets held for sale represent the assets that were expected to be sold, net of liabilities that were expected to be assumed by the purchaser. As of December 31, 2015, the assets sold in the 2016 Divestiture were classified as held for sale. During the year ended December 31, 2015, the Predecessor recorded an impairment charge of $2.1 million, which was included in impairment on the Predecessor’s Statement of Operations, to adjust the carrying amount of these midstream assets to their estimated fair value, determined based on the expected sales price, less costs to sell. The Predecessor did not have assets classified as held for sale as of December 31, 2016. The following table presents balance sheet data related to the assets held for sale as of December 31, 2015:

In accordance with the FASB’s authoritative guidance on fair value measurements, the Predecessor’s financial assets and liabilities are measured at fair value on a recurring basis. The Predecessor’s financial instruments, including accounts receivable, accounts payable and other payables, are carried at cost, which approximates their respective fair market values due to their short-term maturities. The Predecessor recognizes its non-financial assets and liabilities, such as impaired assets and ARO, at fair value on a non-recurring basis.

The authoritative guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (“Level 1” measurements) and the lowest priority to unobservable inputs (“Level 3” measurements). The three levels of the fair value hierarchy are as follows:

Level 1—Unadjusted quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

Index to Financial Statements

Level 2—Pricing inputs, other than unadjusted quoted prices in active markets included in Level 1, are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument and can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.

Level 3—Pricing inputs are generally less observable from objective sources, requiring internally developed valuation methodologies that result in management’s best estimate of fair value.

The following table reflects the changes in the Predecessor’s ARO during the years ended December 31, 2016 and 2015:

Index to Financial Statements

For the years ended December 31, 2016 and 2015, the Predecessor’s effective tax rate differs from the federal statutory rate of 35% primarily due to state income taxes. The reconciliation of income taxes calculated at the U.S. federal tax statutory rate to the Predecessor’s effective tax rate for the years ended December 31, 2016 and 2015 is set forth below:

Significant components of the Predecessor’s deferred tax assets and liabilities as of December 31, 2016 and 2015, were as follows:

Accounting for uncertainty in income taxes prescribes a recognition threshold and measurement methodology for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. As of December 31, 2016, the Predecessor had no unrecognized tax benefits. With respect to income taxes, the Predecessor’s policy is to account for interest charges as interest expense and any penalties as tax expense in its Statements of Operations.

Restricted Stock Awards. The direct employees of the Predecessor have been granted restricted stock awards by Oasis under its Amended and Restated 2010 Long Term Incentive Plan, which vest over a three-year period. The maximum number of shares available for grant under the Amended and Restated 2010 Long Term Incentive Plan is 16,050,000. The fair value of restricted stock grants is based on the value of Oasis’s common stock on the date of grant. Compensation expense is recognized ratably over the requisite service period. Oasis assumed annual forfeiture rates by the employee group ranging from 4.6% to 6.3% based on the forfeiture history for this type of award.

Index to Financial Statements

The following table summarizes information related to restricted stock held by the Predecessor’s employees for the periods presented:

Stock-based compensation expense recorded for restricted stock awards was $0.9 million and $0.7 million for the years ended December 31, 2016 and 2015, respectively, and is included in general and administrative expenses on the Predecessor’s Statements of Operations. The fair value of restricted stock awards vested was $0.2 million for both of the years ended December 31, 2016 and 2015. The weighted average grant date fair value of restricted stock awards granted was $6.63 per share and $13.01 per share for the years ended December 31, 2016 and 2015, respectively. Unrecognized expense as of December 31, 2016 for all non-vested restricted stock awards was $1.4 million and will be recognized over a weighted average period of 1.9 years.

For the years ended December 31, 2016 and 2015, the Predecessor had an associated tax benefit of $0.6 million and $0.3 million, respectively, related to stock-based compensation included in the net parent investment on its Balance Sheets.

Included below is a discussion of various future commitments of the Predecessor as of December 31, 2016. The commitments under these arrangements are not recorded in the accompanying Balance Sheets. The amounts disclosed represent undiscounted cash flows on a gross basis, and no inflation elements have been applied.

Purchase Agreement. As of December 31, 2016, the Predecessor had an agreement for the purchase of freshwater with an aggregate future commitment of approximately $2.2 million. For the years ended December 31, 2016 and 2015, the Predecessor purchased $6.7 million and $13.8 million of freshwater related to this agreement.

The estimable future commitments under this purchase agreement as of December 31, 2016 are as follows:

Environmental Obligations. The Predecessor is subject to federal, state and local regulations regarding air and water quality, hazardous and solid waste disposal and other environmental matters. The Predecessor believes there are currently no such matters that will have a material adverse effect on its results of operations, cash flows or financial position.

Index to Financial Statements

Parent Senior Unsecured Notes. As of December 31, 2016, Oasis had $2.1 billion of senior unsecured notes, which are guaranteed by its material wholly owned subsidiaries (the “Guarantors”), including OMS. These guarantees are full and unconditional and joint and several among the Guarantors. As a Guarantor, OMS has been designated as restricted under the indentures governing Oasis’s senior unsecured notes and is subject to the obligation of these notes.

Credit Risk. The Predecessor is dependent on Oasis as its most significant current customer, as nearly 100% of its revenues came from Oasis for the years ended December 31, 2016 and 2015, and it expects to derive a substantial majority of its revenues from Oasis for the foreseeable future. As a result, any event, whether in its dedicated areas or otherwise, that adversely affects Oasis’s production, drilling schedule, financial condition, leverage, market reputation, liquidity, results of operations or cash flows may adversely affect the Predecessor’s revenues and net income. Further, the Predecessor is subject to the risk of non-payment or non-performance by Oasis. The Predecessor cannot predict the extent to which Oasis’s business would be impacted if conditions in the energy industry were to deteriorate, nor can the Predecessor estimate the impact such conditions would have on Oasis’s ability to fulfill its obligations to the Predecessor. Any material non-payment or non-performance by Oasis could reduce the ability of the Predecessor to continue its business, as Oasis is its primary customer, without marketing its services to third party customers.

Litigation. The Predecessor is party to various legal and/or regulatory proceedings from time to time arising in the ordinary course of business. While the ultimate outcome and impact cannot be predicted with certainty, the Predecessor believes that all such matters are without merit and involve amounts which, if resolved unfavorably, either individually or in the aggregate, will not have a material adverse effect on the Predecessor’s financial condition, results of operations or cash flows. When the Predecessor determines that a loss is probable of occurring and is reasonably estimable, the Predecessor accrues an undiscounted liability for such contingencies based on its best estimate using information available at the time. The Predecessor discloses contingencies where an adverse outcome may be material, or in the judgment of management, the matter should otherwise be disclosed.

The Predecessor has evaluated the period after the balance sheet date through April 7, 2017, noting no subsequent events or transactions that required recognition or disclosure in the financial statements, other than as noted below.

On March 23, 2017, Mirada Energy, LLC, Mirada Wild Basin Holding Company, LLC and Mirada Energy Fund I, LLC (collectively, “Mirada”) filed a lawsuit against Oasis, OPNA and OMS, seeking monetary damages in excess of $100 million, declaratory relief, attorneys’ fees and costs (Mirada Energy, LLC, et al. v. Oasis Petroleum North America LLC, et al.; in the 334th Judicial District Court of Harris County, Texas; Case Number 2017-19911). Mirada asserts that it is a working interest owner in certain acreage owned and operated by Oasis in Wild Basin. Specifically, Mirada asserts that Oasis has breached certain agreements by: failing to allow Mirada to participate in Oasis’s midstream operations in Wild Basin; refusing to provide Mirada with information that Mirada contends is required under certain agreements and failing to provide information in a timely fashion; failing to consult with Mirada and failing to obtain Mirada’s consent prior to drilling more than one well at a time in Wild Basin; and by overstating the estimated costs of proposed well operations in Wild Basin. Mirada seeks a declaratory judgment that OPNA be removed as operator in Wild Basin at Mirada’s election and that Mirada be allowed to elect a new operator; certain agreements apply to Oasis and Mirada and Wild Basin with respect to this dispute; Oasis be required to provide all information within its possession regarding proposed or ongoing operations in Wild Basin; and OPNA not be permitted to drill, or propose to drill, more than one well at a time in Wild Basin without obtaining Mirada’s consent. Mirada also seeks a declaratory judgment with respect to Oasis’s current midstream operations in Wild Basin. Specifically, Mirada seeks a declaratory judgment that Mirada has a right to participate in Oasis’s Wild Basin midstream operations, consisting of produced water disposal, crude oil gathering and gas gathering and processing; that, upon Mirada’s election to participate, Mirada is obligated to

Index to Financial Statements

pay its proportionate costs of Oasis’s midstream operations in Wild Basin; and that Mirada would then be entitled to receive a share of revenues from the midstream operations and would not be charged any amount for its use of these facilities for production from the “Contract Area”.

Oasis believes that Mirada’s claims are without merit, that Oasis has complied with its obligations under the applicable agreements and that some of Mirada’s claims are grounded in agreements which do not apply to Oasis. Oasis intends to vigorously defend against Mirada’s claims and, to the extent the Predecessor is made a party to the suit, it intends to vigorously defend itself against such claims. However, neither the Predecessor nor Oasis can predict or guarantee the ultimate outcome or resolution of such matter. If such matter were to be determined adversely to the Predecessor’s or Oasis’s interests, or if the Predecessor or Oasis were forced to settle such matter for a significant amount, such resolution or settlement could have a material adverse effect on the Predecessor’s 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 the Predecessor in their current assets and future midstream opportunities and related revenues in Wild Basin.

Index to Financial Statements

In our opinion, the accompanying balance sheets present fairly, in all material respects, the financial position of Oasis Midstream Partners LP (the “Partnership”) as of December 31, 2016 and 2015 in conformity with accounting principles generally accepted in the United States of America. These balance sheets are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these balance sheets based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States) and in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the balance sheets are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the balance sheets, assessing the accounting principles used and significant estimates made by management, and evaluating the overall balance sheet presentation. We believe that our audits of the balance sheets provide a reasonable basis for our opinion.

Index to Financial Statements

Oasis Midstream Partners LP (the “Partnership”) is a Delaware limited partnership formed by Oasis Petroleum Inc. (together with its subsidiaries, “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.

Oasis contributed $1,000 in the form of accounts receivable to the Partnership in connection with its formation. There have been no other transactions involving the Partnership as of the date of issuance of these financial statements.

In connection with the completion of this offering, the Partnership intends to offer common units representing limited partner interests pursuant to a public offering and to concurrently issue common units and subordinated units, representing additional limited partner interests in the Partnership, to Oasis and a non-economic general partner interest and all of its incentive distribution rights to OMP GP LLC, a wholly-owned subsidiary of Oasis.

The Partnership has evaluated the period after the balance sheet date, noting no subsequent events or transactions that required recognition or disclosure in the financial statement.

Index to Financial Statements

Through and including , 2017 (25 days after the date of this prospectus), all dealers that buy, sell or trade our common units, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealers’ obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.

Index to Financial Statements

Set forth below are the expenses (other than underwriting discounts) expected to be incurred in connection with the issuance and distribution of the securities registered hereby. With the exception of the SEC registration fee, the FINRA filing fee and the NYSE listing fee, the amounts set forth below are estimates.

Subject to any terms, conditions or restrictions set forth in the partnership agreement, Section 17-108 of the Delaware Revised Uniform Limited Partnership Act empowers a Delaware limited partnership to indemnify and hold harmless any partner or other persons from and against all claims and demands whatsoever. The section of the prospectus entitled “The Partnership Agreement—Indemnification” discloses that we will generally indemnify officers, directors and affiliates of our general partner to the fullest extent permitted by the law against all losses, claims, damages or similar events and is incorporated herein by this reference. We may enter into indemnity agreements with each of the current directors and officers of our general partner to give these directors and officers additional contractual assurances regarding the scope of the indemnification set forth in our general partner’s limited liability company agreement and our partnership agreement and to provide additional procedural protections.

Our general partner will purchase insurance covering its officers and directors against liabilities asserted and expenses incurred in connection with their activities as officers and directors of our general partner or any of its direct or indirect subsidiaries.

The underwriting agreement to be entered into in connection with the sale of the securities offered pursuant to this registration statement, the form of which will be filed as an exhibit to this registration statement, provides for indemnification of Oasis Petroleum Inc. and our general partner, their officers and directors, and any person who controls Oasis Petroleum Inc. and our general partner, including indemnification for liabilities under the Securities Act.

On June 26, 2014, in connection with the formation of Oasis Midstream Partners LP, we issued (i) the non-economic general partner interest in us to OMP GP LLC and (ii) the 100% limited partner interest in us to Oasis Midstream Services LLC in exchange for $1,000.00, in each case in an offering exempt from registration under Section 4(a)(2) of the Securities Act. There have been no other sales of unregistered securities within the past three years.

Index to Financial Statements

We have granted the underwriters a 30-day option to purchase up to an aggregate of additional common units. To the extent that the underwriters do not exercise their option to purchase such additional common units, in whole or in part, any remaining common units will be issued to Oasis at the expiration of the option period for no additional consideration in a private placement pursuant to Section 4(a)(2) of the Securities Act, not pursuant to the offering and sale covered by this Registration Statement.

Reference is made to the Exhibit Index following the signature page hereto, which Exhibit Index is hereby incorporated by reference into this item.

The undersigned registrant hereby undertakes to provide to the underwriters at the closing specified in the underwriting agreement certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser.

Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

The undersigned registrant hereby undertakes that, for the purpose of determining liability of the registrant under the Securities Act to any purchaser in the initial distribution of the securities, in a primary offering of securities of the undersigned registrant pursuant to this registration statement, regardless of the underwriting method used to sell the securities to the purchaser, if the securities are offered or sold to such purchaser by means of any of the following communications, the undersigned registrant will be a seller to the purchaser and will be considered to offer or sell such securities to such purchaser:

(1) Any preliminary prospectus or prospectus of the undersigned registrant relating to the offering required to be filed pursuant to Rule 424;

(2) Any free writing prospectus relating to the offering prepared by or on behalf of the undersigned registrant or used or referred to by the undersigned registrant;

(3) The portion of any other free writing prospectus relating to the offering containing material information about the undersigned registrant or its securities provided by or on behalf of the undersigned registrant; and

(4) Any other communication that is an offer in the offering made by the undersigned registrant to the purchaser.

(1) For purposes of determining any liability under the Securities Act, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this registration statement as of the time it was declared effective.

Index to Financial Statements

(2) For the purpose of determining any liability under the Securities Act, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

The undersigned registrant undertakes that, for the purposes of determining liability under the Securities Act to any purchaser, if the registrant is subject to Rule 430C, each prospectus filed pursuant to Rule 424(b) as part of a registration statement relating to an offering, other than registration statements relying on Rule 430B or other than prospectuses filed in reliance on Rule 430A, shall be deemed to be part of and included in the registration statement as of the date it is first used after effectiveness. Provided, however, that no statement made in a registration statement or prospectus that is part of the registration statement or made in a document incorporated or deemed incorporated by reference into the registration statement or prospectus that is part of the registration statement will, as to a purchaser with a time of contract of sale prior to such first use, supersede or modify any statement that was made in the registration statement or prospectus that was part of the registration statement or made in any such document immediately prior to such date of first use.

The undersigned registrant undertakes to send to each common unitholder, at least on an annual basis, a detailed statement of any transactions with its general partner or its general partner’s affiliates, and of fees, commissions, compensation and other benefits paid, or accrued to its general partner or its general partner’s affiliates for the fiscal year completed, showing the amount paid or accrued to each recipient and the services performed.

The registrant undertakes to provide to the common unitholders the financial statements required by Form 10-K for the first full fiscal year of operations of the registrant.

Index to Financial Statements

Pursuant to the requirements of the Securities Act of 1933, as amended, the registrant has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Houston, State of Texas, on May 12, 2017.

Each person whose signature appears below appoints Thomas B. Nusz and Taylor L. Reid, and each of them, as his true and lawful attorneys-in-fact and agents, with full power of substitution and re-substitution, for him and in his name, place and stead, in any and all capacities, to sign any and all amendments (including post-effective amendments) to this Registration Statement and any Registration Statement (including any amendment thereto) for this offering that is to be effective upon filing pursuant to Rule 462(b) under the Securities Act of 1933, as amended, and to file the same, with all exhibits thereto, and all other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorney-in-fact and agent full power and authority to do and perform each and every act and thing requisite and necessary to be done, as fully to all intents and purposes as he might or would do in person, hereby ratifying and confirming all that said attorney-in-fact and agent may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Act of 1933, as amended, this Registration Statement has been signed below by the following persons in the capacities and the dates indicated.


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


	Per Common Unit		Total
Offering price to the public		$		$
Underwriting discounts and commissions		$		$
Proceeds to us (before expenses)		$		$


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.


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


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


INVESTMENT IN OASIS MIDSTREAM PARTNERS LP BY EMPLOYEE BENEFIT PLANS			212
Prohibited Transaction Issues			212
Plan Asset Issues			212
UNDERWRITING			214
Pricing of the Offering			217
Directed Unit Program			217
Selling Restrictions			217


VALIDITY OF OUR COMMON UNITS			223
EXPERTS			223
WHERE YOU CAN FIND MORE INFORMATION			223
INDEX TO FINANCIAL STATEMENTS			F-1
APPENDIX A—FORM OF AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP			A-1


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	%


	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	$


		Morgan Stanley		Citigroup		Wells Fargo Securities


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⁾		$


	Units				Total Consideration
	Number	Percent			Number	Percent
Oasis^(1)(2)(3)				%				%
Purchasers in the offering⁽³⁾				%				%

Total			100	%			100	%


	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						%


	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


	Twelve Months Ending June 30, 2018			Three Months Ending
	Twelve Months Ending June 30, 2018			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	$			$			$			$			$


	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


	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


	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


	Total Quarterly Distribution Per Unit	Marginal Percentage Interest in Distributions
	Total Quarterly Distribution Per Unit	Unitholders			IDR Holders
Minimum Quarterly Distribution	$		100	%		—	%
First Target Distribution	above $ up to $		100	%		—	%
Second Target Distribution	above $ up to $		85	%		15	%
Third Target Distribution	above $ up to $		75	%		25	%
Thereafter	above $		50	%		50	%


	Quarterly Distribution Per Unit Prior to Reset	Marginal Percentage Interest in Distributions						Quarterly Distribution Per Unit Following Hypothetical Reset
	Quarterly Distribution Per Unit Prior to Reset	Unitholders			IDR Holders
Minimum Quarterly Distribution	up to $		100	%		—	%	up to $ ⁽¹⁾
First Target Distribution	above $ up to $		100	%		—	%	above $ up to $ ⁽²⁾
Second Target Distribution	above $ up to $		85	%		15	%	above $ up to $ ⁽³⁾
Third Target Distribution	above $ up to $		75	%		25	%	above $ up to $ ⁽⁴⁾
Thereafter	above $		50	%		50	%	above $


	Predecessor Historical
	Three Months Ended March 31,									Year Ended December 31,
	2017			2016			Change			2016			2015			Change
	(In thousands)						%			(In thousands)						%
Net cash provided by operating activities	$	20,379		$	19,488			5	%	$	72,086		$	54,143			33	%
Net cash used in investing activities		(23,814	)		(27,445	)		(13	)%		(157,866	)		(120,234	)		31	%
Net cash provided by financing activities		3,435			7,957			(57	)%		85,780			66,091			30	%

Net change in cash	$	—		$	—			—	%	$	—		$	—			—	%


	Payments due by period
Contractual obligations	Total		2017		2018-2019		2020-2021		2022 and thereafter
	(In thousands)
Asset retirement obligations⁽¹⁾	$	1,713	$	—	$	—	$	—	$	1,713
Purchase commitment agreement⁽²⁾		2,234		634		800		800		—

Total contractual cash obligations	$	3,947	$	634	$	800	$	800	$	1,713


Name	Age		Position With Our General Partner
Thomas B. Nusz		57	Chairman of the Board
Taylor L. Reid		54	Chief Executive Officer and Director
Michael H. Lou		42	President and Director
Nickolas J. Lorentzatos		48	Executive Vice President, General Counsel and Corporate Secretary and Director
Richard N. Robuck		42	Senior Vice President and Chief Financial Officer


Name of Beneficial Owner	Common Units Beneficially Owned	Percentage of Common Units Beneficially Owned⁽¹⁾		Subordinated Units Beneficially Owned		Percentage of Subordinated Units Beneficially Owned			Percentage of Common and Subordinated Units Beneficially Owned
Oasis⁽²⁾⁽³⁾			%				100	%		%
Thomas B. Nusz					—		—
Taylor L. Reid					—		—
Michael H. Lou					—		—
Nickolas J. Lorentzatos					—		—
Richard N. Robuck					—		—
All directors and executive officers as a group ( persons)					—		—


Name of Beneficial Owner	Shares Beneficially Owned	Percentage of Shares Beneficially Owned
Thomas B. Nusz
Taylor L. Reid
Michael H. Lou
Nickolas J. Lorentzatos
Richard N. Robuck
All directors and executive officers as a group ( persons)


Name		Number of Common Units
Morgan Stanley & Co. LLC
Citigroup Global Markets Inc.
Wells Fargo Securities, LLC
Credit Suisse Securities (USA) LLC
Deutsche Bank Securities Inc.
Goldman Sachs & Co. LLC
J.P. Morgan Securities LLC
RBC Capital Markets, LLC
BOK Financial Securities, Inc.
BB&T Capital Markets, a division of BB&T Securities, LLC
BBVA Securities Inc.
BTIG, LLC
Capital One Securities, Inc.
CIBC World Markets Corp.
Citizens Capital Markets, Inc.
Comerica Securities, Inc.
Heikkinen Energy Securities, LLC
IBERIA Capital Partners L.L.C.
ING Financial Markets LLC
Johnson Rice & Company L.L.C.
Regions Securities LLC
Piper Jaffray & Co.
Tudor, Pickering, Holt & Co. Securities, Inc.

Total



OASIS MIDSTREAM PARTNERS LP UNAUDITED PRO FORMA CONDENSED FINANCIAL STATEMENTS
Introduction			F-2
Unaudited Pro Forma Condensed Balance Sheet as of March 31, 2017			F-4
Unaudited Pro Forma Condensed Statement of Operations for the Year Ended December 31, 2016			F-5
Unaudited Pro Forma Condensed Statement of Operations for the Three Months Ended March 31, 2017			F-6
Notes to Unaudited Pro Forma Condensed Financial Statements			F-7

OASIS MIDSTREAM PARTNERS LP PREDECESSOR UNAUDITED CONDENSED FINANCIAL STATEMENTS
Unaudited Condensed Balance Sheets as of March 31, 2017 and Balance Sheet as of December 31, 2016			F-10
Unaudited Condensed Statements of Operations for the Three Months Ended March 31, 2017 and 2016			F-11
Unaudited Condensed Statements of Changes in Net Parent Investment for the Three Months Ended March 31, 2017			F-12
Unaudited Condensed Statements of Cash Flows for the Three Months Ended March 31, 2017 and 2016			F-13
Notes to Condensed Financial Statements			F-14

OASIS MIDSTREAM PARTNERS LP PREDECESSOR FINANCIAL STATEMENTS
Report of Independent Registered Public Accounting Firm			F-20
Balance Sheets as of December 31, 2016 and 2015			F-21
Statements of Operations for the Years ended December 31, 2016 and 2015			F-22
Statements of Changes in Net Parent Investment for the Years ended December 31, 2016 and 2015			F-23
Statements of Cash Flows for the Years ended December 31, 2016 and 2015			F-24
Notes to Financial Statements			F-25

OASIS MIDSTREAM PARTNERS LP FINANCIAL STATEMENT
Report of Independent Registered Public Accounting Firm			F-38
Unaudited Balance Sheets as of March 31, 2017 and December 31, 2016 and 2015			F-39
Notes to the Financial Statement			F-40


	March 31, 2017
	Predecessor Historical			Pro Forma Adjustments			Pro Forma as Adjusted
	(In thousands)
ASSETS
Current assets
Cash	$	—		$		^(a)	$
Accounts receivable		624			(548	)^(b)		76
Accounts receivable from affiliate		13,110			(1,163	)^(b)		11,947
Insurance receivable		5,157			—			5,157
Prepaid expenses		816			(25	)^(b)		791

Total current assets		19,707			(1,736	)		17,971

Property, plant and equipment		466,911			(37,216	)^(b)		429,695
Less: accumulated depreciation and amortization		(25,597	)		3,138	^(b)		(22,459	)

Total property, plant and equipment, net		441,314			(34,078	)		407,236

Deferred financing costs		—			1,900	^(c)		1,900
Other assets		3			(3	)^(b)		—

Total assets	$	461,024		$			$

LIABILITIES AND NET PARENT INVESTMENT
Current liabilities
Accounts payable	$	1,369		$	(41	)^(b)	$	1,328
Accrued liabilities		21,738			(1,504	)^(b)		20,234
Current income taxes payable		46,421			(46,421	)^(d)		—

Total current liabilities		69,528			(47,966	)		21,562

Asset retirement obligations		1,769			(497	)^(b)		1,272
Deferred income taxes		42,020			(42,020	)^(d)		—

Total liabilities		113,317			(90,483	)		22,834

Net parent investment		347,707			(347,707	)^(f)		—
Common units held by public						^(e)
Common units held by Oasis						^(f)
Subordinated units held by Oasis						^(f)
Non-controlling interests						^(f)

Total liabilities and net parent investment/partners’ capital	$	461,024		$			$


	Year Ended December 31, 2016
	Predecessor Historical			Pro Forma Adjustments			Pro Forma as Adjusted
	(In thousands)
Revenues
Midstream services for Oasis	$	120,258		$	(27,369	)^(b)(g)	$	92,889
Midstream services for third parties		594			(594	)^(b)		—

Total revenues		120,852			(27,963	)		92,889

Operating expenses
Direct operating		29,275			(7,767	)^(b)		21,508
Depreciation and amortization		8,525			(664	)^(b)		7,861
General and administrative		12,112			(671	)^(b)(h)		11,441

Total operating expenses		49,912			(9,102	)		40,810

Operating income		70,940			(18,861	)		52,079
Other income (expense)		(474	)		462	^(b)		(12	)
Interest expense, net of capitalized interest		(5,481	)		4,351	⁽ⁱ⁾		(1,130	)

Income before income taxes		64,985			(14,048	)		50,937
Income tax expense		(24,857	)		24,857	^(d)		—

Net income	$	40,128		$	10,809		$	50,937
Net income attributable to non-controlling interests		—			35,127	^(j)		35,127

Net income attributable to Oasis Midstream Partners LP	$	40,128		$	(24,318	)	$	15,810

Pro forma limited partners’ interest in net income attributable to Oasis Midstream Partners LP
Common units
Subordinated units
Pro forma net income per limited partner unit (basic and diluted)
Common units
Subordinated units
Pro forma weighted average number of limited partner units outstanding (basic and diluted)
Common units
Subordinated units


	Three Months Ended March 31, 2017
	Predecessor Historical			Pro Forma Adjustments				Pro Forma as Adjusted
	(In thousands)
Revenues
Midstream services for Oasis	$	37,367		$	(876	)	^(b)	$	36,491
Midstream services for third parties		273			(273	)	^(b)		—

Total revenues	$	37,640		$	(1,149	)		$	36,491

Operating expenses
Direct operating		9,023			(360	)	^(b)		8,663
Depreciation and amortization		3,458			(231	)	^(b)		3,227
General and administrative		4,396			(131	)	^(b)(h)		4,265

Total operating expenses		16,877			(722	)			16,155

Operating income		20,763			(427	)			20,336
Other income (expense)		(2	)		2		^(b)		—
Interest expense, net of capitalized interest		(1,217	)		935		⁽ⁱ⁾		(282	)

Income before income taxes		19,544			510				20,054
Income tax expense		(7,295	)		7,295		^(d)		—

Net income	$	12,249		$	7,805			$	20,054
Net income attributable to non-controlling interests		—			13,467		^(j)		13,467

Net income attributable to Oasis Midstream Partners LP	$	12,249		$	(5,662	)		$	6,587

Pro forma limited partner’s interest in net income attributable to Oasis Midstream Partners LP
Common units
Subordinated units
Pro forma net income per limited partner unit (basic and diluted)
Common units
Subordinated units
Pro forma weighted average number of limited partner units outstanding (basic and diluted)
Common units
Subordinated units