SUBMITTED CONFIDENTIALLY TO THE DIVISION OF CORPORATION FINANCE ON JULY 24, 2015

AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON                     , 2015

Registration No. 333-            

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Confidential Draft Submission No. 1

Form S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

NOBLE MIDSTREAM PARTNERS LP

(Exact Name of Registrant as Specified in Its Charter)

Delaware	4932	47-3011449
(State or Other Jurisdiction of Incorporation or Organization)	(Primary Standard Industrial Classification Code Number)	(I.R.S. Employer Identification Number)

1001 Noble Energy Way

Houston, Texas 77070

(281) 872-3100

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

Christian S. Kendall

Chief Executive Officer

1001 Noble Energy Way

Houston, Texas 77070

(281) 872-3100

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

Copies to:

G. Michael O’Leary George Vlahakos Andrews Kurth LLP 600 Travis, Suite 4200 Houston, Texas 77002 (713) 220-4200 Douglas E. McWilliams Vinson & Elkins L.L.P. 1001 Fannin St., Suite 2500 Houston, Texas 77002 (713) 758-2222

Approximate date of commencement of proposed sale to the public: As soon as practicable after this Registration Statement becomes effective.

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

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

If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, 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, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer ¨ Accelerated filer ¨                  

Non-accelerated filer x (Do not check if a smaller reporting company) Smaller reporting company ¨

CALCULATION OF REGISTRATION FEE

Title of Each Class of Securities to be Registered	Proposed Maximum Aggregate Offering Price(1)(2)	Amount of Registration Fee(3)
Common units representing limited partner interests	$	$

(1) Includes common units issuable upon the exercise of the underwriters’ option to purchase additional common units.

(2) Estimated solely for the purpose of calculating the amount of the registration fee in accordance with Rule 457(o) under the Securities Act of 1933, as amended.

(3) To be paid in connection with the initial filing of the registration statement.

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.

The information in this 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 is effective. This prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any jurisdiction where the offer or sale is not permitted.

Subject to Completion, dated                     , 2015

PROSPECTUS

Noble Midstream Partners LP

Common Units

Representing Limited Partner Interests

This is the initial public offering of common units representing limited partner interests in Noble Midstream Partners LP. We were recently formed by Noble Energy, Inc., or Noble, and no public market currently exists for our common units. We are offering                 common units in this offering. We expect that the initial public offering price will be between $         and $         per common unit. We intend to apply to list our common units on the New York Stock Exchange under the symbol “NBLX.” We are an “emerging growth company” as that term is used in the Jumpstart Our Business Startups Act of 2012, or the JOBS Act.

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. If you are not an eligible holder at the time of any requested certification in the future, your common units may be subject to redemption.

Investing in our common units involves risk. Please read “Risk Factors” beginning on page 24.

These risks include the following:

• We derive substantially all of our revenue from Noble. If Noble changes its business strategy, alters its current drilling and development plan on our dedicated acreage, or otherwise significantly reduces the volumes of crude oil, natural gas, saltwater or fresh water with respect to which we perform midstream services, our revenue would decline and our business, financial condition, results of operations, cash flows and ability to make distributions to our unitholders would be materially and adversely affected.

• On a pro forma basis, we would not have generated sufficient distributable cash flow to make the payment of the aggregate annualized minimum quarterly distribution on all of our units for the year ended December 31, 2014 or the twelve months ended March 31, 2015.

• We may not generate sufficient distributable cash flow to make the payment of the minimum quarterly distribution to our unitholders.

• Our general partner and its affiliates, including Noble, have conflicts of interest with us and limited fiduciary duties to us and our unitholders, and they may favor their own interests to our detriment and that of our unitholders. Additionally, we have no control over the business decisions and operations of Noble, and Noble is under no obligation to adopt a business strategy that favors us.

• Unitholders have very limited voting rights and, even if they are dissatisfied, they will have limited ability to remove our general partner.

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

• Our tax treatment depends on our status as a partnership for federal income tax purposes. If the Internal Revenue Service were to treat us as a corporation for federal income tax purposes, which would subject us to entity-level taxation, or if we were otherwise subjected to a material amount of entity-level taxation, then our distributable cash flow to our unitholders would be substantially reduced.

• Our unitholders’ share of our income will be taxable to them for federal income tax purposes even if they do not receive any cash distributions from us.

	Per Common Unit	Total
Price to the public	$	$
Underwriting discounts and commissions(1)	$	$
Proceeds to Noble Midstream Partners LP (before expenses)	$	$

(1) Excludes an aggregate structuring fee equal to     % of the gross proceeds from this offering payable to Barclays Capital Inc. and Robert W. Baird & Co. Incorporated. Please read “Underwriting.”

We have granted the underwriters a 30-day option to purchase up to an additional             common units from us on the same terms and conditions as set forth above if the underwriters sell more than             common units in this offering.

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 on or about                     , 2015.

Joint Book-Running Managers

Barclays Baird

Prospectus dated                     , 2015

[INSIDE FRONT COVER ART TO COME]

TABLE OF CONTENTS

	Page
PROSPECTUS SUMMARY		1
Overview		1
Our Existing Assets		3
Business Strategies		5
Competitive Strengths		6
Noble Energy, Inc.		7
Our Emerging Growth Company Status		8
Risk Factors		9
The Transactions		10
Ownership and Organizational Structure		11
Management of Noble Midstream Partners LP		13
Principal Executive Offices and Internet Address		13
Summary of Conflicts of Interest and Duties		13
The Offering		15
Summary Historical and Pro Forma Financial Data		21
RISK FACTORS		24
Risks Related to Our Business		24
Risks Inherent in an Investment in Us		41
Tax Risks		52
USE OF PROCEEDS		57
CAPITALIZATION		58
DILUTION		59
CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS		60
General		60
Our Minimum Quarterly Distribution		62
Unaudited Pro Forma EBITDA and Distributable Cash Flow for the Year Ended December  31, 2014 and Twelve Months Ended March 31, 2015		64
Estimated EBITDA and Distributable Cash Flow for the Twelve Months Ending September 30, 2016		67
Significant Forecast Assumptions		69
PROVISIONS OF OUR PARTNERSHIP AGREEMENT RELATING TO CASH DISTRIBUTIONS		74
Distributions of Available Cash		74
Operating Surplus and Capital Surplus		75
Capital Expenditures		77
Subordinated Units and Subordination Period		78
Distributions of Available Cash from Operating Surplus During the Subordination Period		80
Distributions of Available Cash from Operating Surplus After the Subordination Period		80
Incentive Distribution Rights		80
Percentage Allocations of Available Cash from Operating Surplus		81
Noble’s Right to Reset Incentive Distribution Levels		81
Distributions from Capital Surplus		84
Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels		85
Distributions of Cash Upon Liquidation		85
SELECTED HISTORICAL AND PRO FORMA FINANCIAL DATA		88
Non-GAAP Financial Measure		90
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		92
Overview		92
How We Generate Revenue		92
How We Evaluate Our Operations		93

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	Page
Factors Affecting the Comparability of Our Financial Results		96
Other Factors Impacting Our Business		97
Results of Operations		98
Capital Resources and Liquidity		101
Off-Balance Sheet Arrangements		103
Critical Accounting Polices		103
Contractual Obligations		105
Qualitative and Quantitative Disclosures About Market Risk		105
INDUSTRY OVERVIEW		107
General		107
Crude Oil Midstream Industry		107
Natural Gas Midstream Industry		108
Water Services Industry		109
Market Fundamentals		109
Overview of the DJ Basin		115
BUSINESS		118
Overview		118
Our Existing Assets		119
Noble Energy, Inc.		124
Our Midstream Operations		126
Access to Downstream Markets		136
Our Acreage Dedication		136
Our Commercial Agreements with Noble		138
Right of First Refusal on Assets and Services		139
Title to Our Properties		139
Seasonality		140
Competition		140
Regulation of Operations		141
Environmental Matters		145
Employees		149
Insurance		149
Legal Proceedings		149
MANAGEMENT		150
Management of Noble Midstream Partners LP		150
Committees of the Board of Directors		151
Directors and Executive Officers of Noble Midstream GP LLC		152
Board Leadership Structure		153
Board Role in Risk Oversight		153
Reimbursement of Expenses		153
Compensation of Our Officers and Directors		153
Our Long-Term Incentive Plan		154
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT		157
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS		159
Distributions and Payments to Our General Partner and Its Affiliates		159
Agreements with our Affiliates in Connection with the Transactions		160
Procedures for Review, Approval and Ratification of Related Person Transactions		164
CONFLICTS OF INTEREST AND DUTIES		166
Conflicts of Interest		166
Duties of Our General Partner		173
DESCRIPTION OF OUR COMMON UNITS		176
Our Common Units		176
Transfer Agent and Registrar		176

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	Page
Transfer of Common Units		176
Exchange Listing		177
OUR PARTNERSHIP AGREEMENT		178
Organization and Duration		178
Purpose		178
Capital Contributions		178
Voting Rights		178
Limited Liability		180
Issuance of Additional Partnership Interests		181
Amendment of Our Partnership Agreement		181
Merger, Consolidation, Conversion, Sale or Other Disposition of Assets		183
Termination and Dissolution		184
Liquidation and Distribution of Proceeds		184
Withdrawal or Removal of Our General Partner		185
Transfer of General Partner Interest		186
Transfer of Ownership Interests in Our General Partner		186
Transfer of Incentive Distribution Rights		186
Change of Management Provisions		186
Limited Call Right		186
Possible Redemption of Ineligible Holders		187
Meetings; Voting		188
Status as Limited Partner		189
Indemnification		189
Reimbursement of Expenses		189
Books and Reports		190
Right to Inspect Our Books and Records		190
Registration Rights		190
Applicable Law; Exclusive Forum		190
UNITS ELIGIBLE FOR FUTURE SALE		192
Rule 144		192
Our Partnership Agreement and Registration Rights		192
Lock-Up Agreements		193
Registration Statement on Form S-8		193
MATERIAL FEDERAL INCOME TAX CONSEQUENCES		194
Partnership Status		195
Limited Partner Status		197
Tax Consequences of Unit Ownership		197
Tax Treatment of Operations		203
Disposition of Common Units		203
Uniformity of Units		206
Tax-Exempt Organizations and Other Investors		207
Administrative Matters		207
INVESTMENT IN NOBLE MIDSTREAM PARTNERS LP BY EMPLOYEE BENEFIT PLANS		211
General Fiduciary Matters		211
Prohibited Transaction Matters		212
Plan Asset Issues		212
UNDERWRITING		213
Commissions and Expenses		213
Option to Purchase Additional Common Units		213
Lock-Up Agreements		214
Directed Unit Program		214
Offering Price Determination		215

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	Page
Indemnification		215
Stabilization, Short Positions and Penalty Bids		215
Listing on the New York Stock Exchange		216
Stamp Taxes		216
Other Relationships		216
Direct Participation Plan Requirements		216
Selling Restrictions VALIDITY OF THE COMMON UNITS		217 219
EXPERTS		219
WHERE YOU CAN FIND ADDITIONAL INFORMATION		220
FORWARD-LOOKING STATEMENTS		221
INDEX TO FINANCIAL STATEMENTS		F-1
APPENDIX A—FORM OF FIRST AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP OF NOBLE MIDSTREAM PARTNERS LP		A-1
APPENDIX B—GLOSSARY OF TERMS		B-1

You should rely only on the information contained in this prospectus or in any free writing prospectus prepared by us or on behalf of us or to which we have referred you. We have not, and the underwriters have not, authorized any other person to provide you with information different from that contained in this prospectus and any free writing prospectus. If anyone provides you with different or inconsistent information, you should not rely on it. We are not, and the underwriters are not, making an offer to sell these securities in any jurisdiction where an offer or sale is not 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 our common units. Our business, financial condition, results of operations and prospects may have changed since that date.

Through and including                     , 2015 (the 25th day after the date of this prospectus), federal securities laws may require all dealers that effect transactions in these securities, whether or not participating in this offering, to deliver a prospectus. This requirement is in addition to a dealer’s obligation to deliver a prospectus when acting as an underwriter and with respect to an unsold allotment or subscription.

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 “Forward-Looking Statements.”

Industry and Market Data

The data included in this prospectus regarding the midstream crude oil and natural gas industry, including descriptions of trends in the market, are based on a variety of sources, including independent industry publications, government publications and other published independent sources and publicly available information, as well as our good faith estimates, which have been derived from management’s knowledge and experience in our industry. Although we have not independently verified the accuracy or completeness of the third-party information included in this prospectus, based on management’s knowledge and experience, we believe that the third-party sources are reliable and that the third-party information included in this prospectus or in our estimates is accurate and complete as of the dates presented.

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PROSPECTUS SUMMARY

This summary highlights selected information contained elsewhere in this prospectus. You should carefully read the entire prospectus, including “Risk Factors” and the historical and unaudited pro forma financial statements and related notes included elsewhere in this prospectus before making an investment decision. Unless otherwise indicated, the information in this prospectus assumes (i) 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 (ii) that the underwriters do not exercise their option to purchase additional common units. You should read “Risk Factors” beginning on page 24 for more information about important factors that you should consider before purchasing our common units.

Unless the context otherwise requires, references in this prospectus to “Noble Midstream,” the “Partnership,” “we,” “our,” “us,” or like terms, when used in a historical context, refer to Noble Midstream Partners LP Predecessor, our predecessor for accounting purposes, also referred to as “our Predecessor,” and when used in the present tense or prospectively, refer to Noble Midstream Partners LP and its subsidiaries. References in this prospectus to “our general partner” refer to Noble Midstream GP LLC. References in this prospectus to “Noble” refer collectively to Noble Energy, Inc. (NYSE:NBL) and its subsidiaries, other than us, our subsidiaries and our general partner. We have provided definitions for some of the terms we use to describe our business and industry and other terms used in this prospectus in the “Glossary of Terms” beginning on page B-1 of this prospectus.

Noble Midstream Partners LP

Overview

We are a growth-oriented Delaware master limited partnership recently formed by our sponsor, Noble, to own, operate, develop and acquire a wide range of domestic midstream infrastructure assets. We currently provide crude oil, natural gas, and water-related midstream services for Noble through long-term, fixed-fee contracts. Our operating assets are currently focused in the Denver-Julesburg Basin, or DJ Basin, in Colorado, one of the premier liquid hydrocarbon basins in the United States. Noble intends for us to become its primary vehicle for domestic midstream operations that have not previously been dedicated to other ventures. We believe that our diverse midstream infrastructure assets and our relationship with Noble position us as a leading midstream service provider.

We have entered into multiple fee-based commercial agreements with Noble, each with an initial term of 15 years, utilizing our infrastructure assets to provide an array of services critical to Noble’s upstream operations. Our agreements include substantial acreage dedications. See “Business—Our Acreage Dedication.” These long-term, fee-based commercial agreements are intended to mitigate our direct commodity price exposure and enhance the stability of our cash flows. In the future, we intend to seek similar commercial arrangements with unaffiliated third parties.

Noble is one of the largest producers of liquids in the DJ Basin, where it produced, on average, 101 MBoe/d of crude oil, condensate, natural gas and natural gas liquids, or NGLs, during 2014, with 66% of such volumes being crude oil and NGLs. Noble’s sales volumes in the DJ Basin increased to 116 MBoe/d in the three months ended March 31, 2015, with 64% of such volumes being crude oil and NGLs. For the three months ended March 31, 2015, we provided crude oil and natural gas gathering services with respect to an average of approximately 31 MBoe/d. As of December 31, 2014, Noble’s estimated net proved reserves in the DJ Basin were 451 MMBoe, of which approximately 61% was crude oil, condensate and NGLs.

Noble commenced horizontal drilling in the DJ Basin in 2010 in order to increase recoveries of liquid-rich hydrocarbons. This shift to a horizontal drilling program has created an opportunity for more efficient gathering

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of crude oil, natural gas, NGLs and water, which is the core of our business. Noble is testing a number of drilling and completion techniques to increase efficiencies and ultimate recovery while enhancing the overall value of its DJ Basin position. Noble accelerated its extended reach lateral well program to approximately 32% of wells drilled in 2014. During the year ended December 31, 2014, Noble spud 303 horizontal wells, of which 96 were extended reach lateral wells, and 310 wells initiated production. Since January 2010, Noble has spud over 900 horizontal wells, covering over four million lateral feet.

The table below shows Noble’s DJ Basin drilling activities for the past three years ended December 31.

	Year Ended December 31,
	2012		2013		2014
Number of horizontal wells spud		193		285		303
Approximate average lateral feet per horizontal well		4,200		4,400		5,600

The graph below shows Noble’s DJ Basin horizontal production and drilling activity from January 1, 2010 through March 31, 2015, and demonstrates the impact that the horizontal drilling program has had on Noble’s DJ Basin production. A number of factors impact Noble’s production and drilling activity, including the number of drilling rigs that Noble operates on its acreage. See “Risk Factors—Risks Related to Our Business.”

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In addition to its DJ Basin assets, pursuant to its acquisition of Rosetta Resources Inc. completed on July 20, 2015, Noble acquired certain Eagle Ford Shale and Permian Basin assets. Noble anticipates a compounded annual production growth rate from its newly acquired Eagle Ford Shale and Permian Basin assets over the next several years of approximately 15% in aggregate. These assets had proved reserves of 282 MMBoe for the year ended December 31, 2014 and average production for the second quarter of 2015 of approximately 63 MBoe/d. More than 60% of the current production and proved reserves for these assets are liquids.

Our Existing Assets

We operate and own interests in crude oil gathering pipelines, crude oil treating facilities, natural gas gathering pipelines and a centralized gathering facility, or CGF. In addition, we provide Noble with water-related services that are critical to Noble’s upstream operations, including the storage and distribution of fresh water for use in drilling and completion operations and collecting, cleaning, recycling and disposing of flowback and produced water, which we refer to collectively as saltwater, through our interests in pipelines and facilities (or under contracts with third parties). The majority of our current facilities are located in two areas of Weld County, Colorado, that we refer to as the Wells Ranch integrated development plan area, or Wells Ranch IDP, and the East Pony integrated development plan area, or East Pony IDP. Each integrated development plan area, or IDP area, consists of a large block of Noble’s contiguous acreage, allowing us to build and operate midstream infrastructure that we believe is more efficient in terms of capital invested per mile of pipe and service provided. Noble develops the IDP areas through a comprehensive design for well pad facilities that support horizontal drilling allowing us to efficiently gather production and provide midstream services to these areas with reduced truck traffic, emissions and overall surface footprint.

To effectively manage our growth, capital expenditure requirements and balance sheet, we have divided our initial assets and those that we expect to develop in the future between two categories, which we refer to as our “Core Assets” and “Growth Assets,” based on their current expected cash flows, growth profiles, capital expenditure requirements and the expected timing of their development.

Core Assets

Our Core Assets include the assets that generate substantially all of our current cash flows. We expect these assets to be key contributors to our growth in the near-term as Noble continues to increase its production in the DJ Basin through the execution of its horizontal drilling plan. Except for our interest in White Cliffs LLC described below, all of our Core Assets are owned by a development company in which we own an initial     % controlling interest.

Our Core Assets include gathering systems in the Wells Ranch IDP that collect crude oil, natural gas and saltwater from facilities located at or near the wellhead and provide gathering to the Wells Ranch CGF or other delivery points within the IDP area. At the Wells Ranch CGF, we provide certain integral services, including separation, treatment, cleaning and storage of the incoming liquid stream into pipeline-quality crude oil and saltwater suitable for disposal or recycling operations. At the tailgate of the Wells Ranch CGF, we deliver the hydrocarbons to a third party for additional gathering and processing and we collect and clean the saltwater and prepare it for treating, recycling and disposal, with a portion of this water returning to our fresh water system after recycling. We expect these systems and others that we may develop in other IDP areas in the future will provide us and Noble many benefits, including increased capital and operating efficiencies. Our Core Assets servicing the Wells Ranch IDP include:

• approximately 25 miles of liquids pipelines that carry both crude oil and saltwater servicing the Wells Ranch IDP, which had, during the three months ended March 31, 2015:

^¡   average daily throughput of approximately 16,800 Bbl/d of crude oil; and

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^¡   average daily throughput of approximately 3,600 Bbl/d of saltwater;

• approximately 30 miles of natural gas gathering pipelines servicing the Wells Ranch IDP, which had average daily throughput of approximately 63,400 Mcf/d as of March 31, 2015;

• storage capacity for up to 96,000 Bbls of crude oil and 32,000 Bbls of saltwater at the Wells Ranch CGF;

• approximately 20 miles of fresh water pipelines servicing the Wells Ranch IDP that delivered an average of approximately 2,000 Bbl/d of fresh water during the three months ended March 31, 2015; and

• a fresh water storage system servicing the Wells Ranch IDP, which had a storage capacity of 500,000 Bbls of fresh water as of March 31, 2015.

In addition to our assets servicing the Wells Ranch IDP, we operate the following Core Assets:

• approximately 15 miles of crude oil gathering pipelines servicing the East Pony IDP, which had average daily throughput of approximately 2,600 Bbl/d of crude oil during the three months ended March 31, 2015;

• the Briggsdale and Platteville crude oil treating facilities, which have an annual operating capacity of 1,825,000 Bbls and 2,740,000 Bbls, respectively.

In addition to the Core Assets described above, all of which are owned by a development company that we control, we own a 3.33% ownership interest in White Cliffs Pipeline, L.L.C., or White Cliffs LLC, which entitles us to distributions based on our pro rata share of monthly net cash flow generated by the operation of the White Cliffs Pipeline. The White Cliffs Pipeline has a current capacity of approximately 150,000 Bbl/d of crude oil and is undergoing an expansion to increase the pipeline’s crude oil capacity to approximately 215,000 Bbl/d. See “Business—Our Existing Assets—Core Assets.”

Growth Assets

Our Growth Assets are held by a number of development companies in which we own initial controlling interests ranging from     % to     %. We believe this tiered ownership structure will allow us to maintain flexibility to adjust to Noble’s development decisions. Our Growth Assets include:

• the East Pony IDP fresh water system, which consists of approximately 10 miles of pipelines and a storage capacity of 550,000 Bbls of water as of March 31, 2015 and an average daily throughput of approximately 25,000 Bbl/d during the three months ended March 31, 2015;

• surface leases with partial construction of fresh water systems and rights-of-way located in the Mustang IDP that will permit crude oil, natural gas and water infrastructure to be constructed and a dedication from Noble covering production from Noble’s net mineral acreage in the Mustang IDP pursuant to which we are entitled to provide all crude oil, natural gas and water midstream services that were not previously dedicated to a third party;

• a dedication from Noble covering production from Noble’s net mineral acreage in the Greeley Crescent IDP pursuant to which we are entitled to provide crude oil and water midstream services; and

• a dedication from Noble covering production from Noble’s net mineral acreage in the Bronco IDP pursuant to which we are entitled to provide crude oil and water midstream services.

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The following table provides a summary of our assets, services and dedicated net acreage (as of March 31, 2015) along with our ownership of these assets as of the closing of this offering.

	Area Served	NBLX Dedicated Service	Approximate Dedicated Net Acreage	NBLX Ownership Interest
Core Assets(1)	Wells Ranch IDP	•     Crude Oil Gathering •     Natural Gas Gathering(2) •     Water Services	65,000	%
	East Pony IDP All Noble DJ Basin Acreage	•     Crude Oil Gathering •     Crude Oil Treating	40,000 N/A(3)
Growth Assets	Mustang IDP(4)	•     Crude Oil Gathering •     Natural Gas Gathering(2) •     Water Services	80,000	%
	Greeley Crescent IDP(4)	•     Crude Oil Gathering •     Water Services	65,000	%
	Bronco IDP(4)	•     Crude Oil Gathering •     Water Services	50,000	%
	East Pony IDP	•     Water Services	40,000	%

(1) Our Core Assets also include a 3.33% ownership interest in White Cliffs LLC, which is not held through a development company.

(2) We provide natural gas gathering services in the Wells Ranch IDP, and we expect to provide natural gas gathering services in the Mustang IDP, from Noble’s centralized wellhead equipment to third parties. See “Business—Our Existing Assets.”

(3) We charge Noble fixed fees based on the number of Noble-operated wells with access to our crude oil treating facilities. As of March 31, 2015, we serviced and collected fees in respect of 6,340 Noble-operated wells at our crude oil treating facilities.

(4) We currently have limited midstream infrastructure assets in the Mustang IDP and no midstream infrastructure assets in the Greeley Crescent IDP and Bronco IDP. Our assets in these IDP areas currently consist primarily of dedications to us from Noble for future production in these IDP areas. In the Mustang IDP, we also own certain rights-of-way and surface leases. See “Business—Our Existing Assets.”

Business Strategies

Our principal business objectives are to generate stable cash flows and increase the quarterly cash distributions that we pay to our unitholders over time while ensuring the ongoing stability of our business by providing outstanding service to our upstream customers. We expect to achieve these objectives through the following business strategies:

• Acting as the primary provider of midstream services in Noble’s dedicated areas. Our midstream infrastructure currently serves Noble’s production on its substantial acreage in the DJ Basin, from which Noble produced an average of 116 MBoe/d of crude oil, condensate, natural gas and NGLs during the

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first quarter of 2015. During this time period, we provided crude oil and natural gas gathering services with respect to an average of approximately 31 MBoe/d. Noble has dedicated, until 2030, certain midstream services to us on this substantial acreage position in the DJ Basin. See “Business—Our Acreage Dedication.” We expect Noble’s production volumes to grow from its future horizontal drilling activities, which we anticipate will help us maintain and grow throughput on our crude oil, natural gas and saltwater midstream infrastructure and increase demand for our fresh water services. We are strategically positioned to expand our delivery of midstream services within the areas dedicated to us as Noble executes on its drilling and development plans.

• Pursuing accretive acquisitions from Noble and third parties. After this offering, Noble will be the sole owner of our general partner and will own a     % limited partner interest in us, consisting of              common units and all of our subordinated units and incentive distribution rights and its retained non-controlling interests in our Core Assets and Growth Assets. Noble has granted us a right of first refusal, or ROFR, on its retained interests in the development companies that hold our assets as well as certain midstream assets that it retains, acquires or develops in the future to the extent such assets are not subject to a third party purchase right, including any assets acquired in connection with its acquisition of Rosetta Resources Inc. on July 20, 2015. We expect Noble to be strongly incentivized to help us grow our business, including by offering us the opportunity to acquire midstream assets it has retained, develops or acquires in the future and elects to sell. In addition, we expect to identify and pursue accretive third-party acquisitions.

• Attracting third-party business. In addition to being an integral provider of midstream services for Noble’s production in the DJ Basin, we intend to market our services to, and pursue strategic relationships with, third-party producers over the long term. We believe that our portfolio of assets and execution and operational capabilities will position us favorably to compete for third-party production both inside and outside the DJ Basin. However, we do not know when or if such relationships with third-party producers will develop.

• Focusing on stable, fixed-fee arrangements to mitigate our direct commodity price exposure and enhance the stability of our cash flows. Our commercial agreements with Noble are structured as long-term, fixed-fee arrangements, and we intend to continue to pursue additional long-term, fixed-fee arrangements with Noble and third parties. We will pursue additional long-term commitments from customers, which may include throughput-based charges, reservation-based charges, volume commitments or acreage dedications.

Competitive Strengths

We believe we are well-positioned to successfully execute our business strategies because of the following competitive strengths:

• Strategic relationship with Noble. We have a strategic relationship with Noble, one of the leading producers of crude oil, condensate, natural gas and NGLs in the DJ Basin and North America. As the owner of our general partner, all of our incentive distribution rights, a     % limited partner interest in us and its retained, non-controlling interests in the development companies that hold our assets, we believe Noble will be incentivized to promote and support our business plan and to pursue projects that enhance the overall value of our business. Through our long-term commercial agreements with Noble, we have a well-capitalized, investment grade commercial counterparty initially responsible for all of our revenues. We believe that our relationship with Noble will provide us with a stable base of cash flows and significant growth opportunities.

• Strategically located assets. Our initial midstream infrastructure assets are located on and around Noble’s significant, contiguous acreage in the DJ Basin and serve Noble’s current and future production on this acreage. Noble commenced operations in Weld County, Colorado, in 2005 and currently holds one of the largest acreage positions in the DJ Basin. The DJ Basin has been the focus of extensive

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industry activity over the last several years, and we expect producers to continue to invest substantial capital to develop crude oil and natural gas production in this region, which will in turn require substantial investment in midstream infrastructure. We also expect Noble’s use of integrated development plans to help us manage capital expenditures because Noble’s development under these plans is intended to centrally locate production and midstream infrastructure rather than replicate services and infrastructure at each wellhead, which will allow us to efficiently gather Noble’s production from centralized wellhead equipment. In addition, Noble’s strategic, contiguous acreage provides us an opportunity to provide water-related services both at the initial stages of well development and at the tailgate of our midstream facilities. We believe that our existing footprint, coupled with Noble’s dedications, positions us to capitalize on midstream growth opportunities on Noble’s contiguous DJ Basin acreage.

• Long-term, fixed-fee contracts to support cash flows. We service Noble’s liquids-rich production in the DJ Basin pursuant to long-term, fixed-fee contracts. For the twelve months ended March 31, 2015, Noble represented all of our gathering volumes. We have secured dedications from Noble under which we will provide our crude oil, natural gas and water services pursuant to 15-year, fixed-fee contracts. We believe that Noble’s horizontal drilling activity and potential new third-party customers will drive the stable growth of our midstream operations. Our contract structure mitigates our direct exposure to commodity price risk contributing to long-term cash flow stability.

• Financial flexibility and strong capital structure. At the closing of this offering, we expect to have $         million of availability under our new, undrawn revolving credit facility. We believe that our available borrowing capacity and our expected ability to access debt and equity capital markets provide us with the financial flexibility necessary to execute our business strategy.

• Experienced management and operating teams. Our executive management team has an average of over          years of experience in designing, acquiring, building, operating, financing and otherwise managing large-scale midstream and other energy assets. In addition, through our omnibus services agreement with Noble, we employ engineering, construction and operations teams that have significant experience in designing, constructing and operating large scale midstream and other energy assets.

Noble Energy, Inc.

Overview

Noble is a global independent oil and natural gas exploration and production company, with total proved reserves of 1.7 billion Boe at year-end 2014 (pro forma for the acquisition of Rosetta Resources Inc.). Noble’s diverse resource base includes positions in four premier unconventional U.S. onshore plays - the DJ Basin, Marcellus Shale, Eagle Ford Shale and Permian Basin - and offshore in the U.S. Gulf of Mexico, Eastern Mediterranean and West Africa. Noble is listed on the NYSE under the symbol “NBL” and had a market capitalization of approximately $16.5 billion as of December 31, 2014.

Noble is one of the largest producers of liquids in the DJ Basin, where it produced, on average, 101 MBoe/d of crude oil, condensate, natural gas and NGLs during 2014, with 66% of such volumes being crude oil and NGLs. Noble’s sales volumes in the DJ Basin increased to 116 MBoe/d in the three months ended March 31, 2015, with 64% of such volumes being crude oil and NGLs. As of December 31, 2014, Noble’s reported estimated net proved reserves in the DJ Basin were 451 MMBoe, of which approximately 61% was crude oil, condensate and NGLs.

Noble continually evaluates strategic additions to its reserves in North America. On July 20, 2015, Noble acquired approximately 50,000 net acres in the Eagle Ford Shale in south Texas and 56,000 net acres in the

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Permian Basin in west Texas (46,000 net acres in the Delaware Basin and 10,000 net acres in the Midland Basin) in connection with its acquisition of Rosetta Resources Inc. Noble has identified in excess of 1,800 gross horizontal drilling locations for development in this newly acquired acreage.

Our Relationship with Noble

One of our principal strengths is our relationship with Noble. In connection with the completion of this offering, we will (i)             issue common units and             subordinated units to Noble, representing 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), (ii) issue a non-economic general partner interest in us to our general partner and issue all of our incentive distribution rights to Noble and (iii) use the net proceeds from this offering to make a distribution of approximately $             million to Noble. Please read “—The Offering,” “Use of Proceeds,” “Security Ownership of Certain Beneficial Owners and Management” and “Certain Relationships and Related Party Transactions—Distributions and Payments to Our General Partner and Its Affiliates.”

Given Noble’s significant ownership interest in us following this offering and its intent to use us as its primary domestic midstream service provider in areas that have not previously been dedicated to other ventures, we believe that Noble will be incentivized to promote and support the successful execution of our business strategies; however, we can provide no assurances that we will benefit from our relationship with Noble. While our relationship with Noble is a significant strength, it is also a source of potential risks and conflicts. Please read “Risk Factors—Risks Inherent in an Investment in Us” and “Conflicts of Interest and Duties.”

Our Emerging Growth Company Status

As a company with less than $1.0 billion in revenue during its last fiscal year, we qualify as an “emerging growth company” as defined in 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 this prospectus;

• deferral of 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 $1.0 billion in annual revenue, (iii) the date on which we issue more than $1.0 billion of non-convertible debt over a three-year period and (iv) the date on which we are deemed to be a “large accelerated filer,” as defined in Rule 12b-2 promulgated under the Securities Exchange Act of 1934, as amended, or the Exchange Act.

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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. Below is a summary of certain key risk factors that you should consider in evaluating an investment in our common units. However, this list is not exhaustive. Please read “Risk Factors” and “Forward-Looking Statements.”

Risks Related to Our Business

• We derive substantially all of our revenue from Noble. If Noble changes its business strategy, alters its current drilling and development plan on our dedicated acreage, or otherwise significantly reduces the volumes of crude oil, natural gas, saltwater or fresh water with respect to which we perform midstream services, our revenue would decline and our business, financial condition, results of operations, cash flows and ability to make distributions to our unitholders would be materially and adversely affected.

• On a pro forma basis, we would not have generated sufficient distributable cash flow to make the payment of the aggregate annualized minimum quarterly distribution on all of our units for the year ended December 31, 2014 or the twelve months ended March 31, 2015.

• We may not generate sufficient distributable cash flow to make the payment of the minimum quarterly distribution to our unitholders.

• The assumptions underlying the forecast of distributable cash flow that we include in “Cash Distribution Policy and Restrictions on Distributions” are inherently uncertain and subject to significant business, economic, financial, regulatory and competitive risks that could cause our actual distributable cash flow to differ materially from our forecast.

• We cannot predict the rate at which Noble will develop acreage that is dedicated to us or the areas it will decide to develop.

Risks Inherent in an Investment in Us

• Our general partner and its affiliates, including Noble, have conflicts of interest with us and limited fiduciary duties to us and our unitholders, and they may favor their own interests to our detriment and that of our unitholders. Additionally, we have no control over the business decisions and operations of Noble, and Noble is under no obligation to adopt a business strategy that favors us.

• Our partnership agreement requires that we distribute all of our available cash, which could limit our ability to grow and make acquisitions.

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

• Affiliates of our general partner and Noble 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 dedications contained in our commercial agreements and rights of first refusal contained in our omnibus agreement.

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

• 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.

Tax Risks

• Our tax treatment depends on our status as a partnership for federal income tax purposes. If the Internal Revenue Service, or IRS, were to treat us as a corporation for federal income tax purposes, which would subject us to entity-level taxation, or if we were otherwise subjected to a material amount of entity-level taxation, then our distributable cash flow to our unitholders would be substantially reduced.

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

• Our unitholders’ share of our income will be taxable to them for federal income tax purposes even if they do not receive any cash distributions from us.

The Transactions

We were formed in December 2014 by Noble. In connection with this offering, Noble will contribute to us the percentages of the development companies that will operate our assets described under “Certain Relationships and Related Party Transactions—Agreements with our Affiliates in Connection with the Transactions—Contribution Agreement.”

In addition, in connection with this offering, we will:

• issue             common units and             subordinated units to Noble, representing an aggregate     % limited partner interest in us;

• issue all of our incentive distribution rights to Noble;

• issue             common units to the public, representing a     % limited partner interest in us, and we will apply the net proceeds as described under “Use of Proceeds;”

• enter into a new $             million revolving credit facility;

• amend and restate our long-term, fixed-fee commercial agreements with Noble;

• enter into an omnibus agreement with Noble and our general partner;

• enter into an operational services agreement with Noble; and

• enter into an employee secondment agreement with Noble.

The number of common units to be issued to Noble includes             common units that will be issued at the expiration of the underwriters’ option to purchase additional common units, assuming that the underwriters do not exercise the option. Any exercise of the underwriters’ option to purchase additional common units would reduce the common units shown as held by Noble by the number to be purchased by the underwriters in connection with such exercise. If and to the extent the underwriters exercise their option to purchase additional common units, the number of common units purchased by the underwriters pursuant to any exercise will be sold to the public, and any remaining common units not purchased by the underwriters pursuant to any exercise of the option will be issued to Noble at the expiration of the option period for no additional consideration. We will use any net proceeds from the exercise of the underwriters’ option to purchase additional common units to make a cash distribution to Noble.

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Ownership and Organizational Structure

After giving effect to the transactions described above, assuming the underwriters’ option to purchase additional common units from us is not exercised, our partnership interests will be held as follows:

Public common units		%
Noble common units		%
Noble subordinated units		%
Noble incentive distribution rights	—	%(1)
General partner interest	—	%(2)
Total	100.0	%

(1) Incentive distribution rights represent a variable interest in distributions and thus are not expressed as a fixed percentage. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions—Incentive Distribution Rights.” Distributions with respect to the incentive distribution rights will be classified as distributions with respect to equity interests. All of our incentive distribution rights will be issued to Noble.

(2) Our general partner owns a non-economic general partner interest in us. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions —Distributions of Available Cash—General Partner Interest.”

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The following simplified diagram depicts our organizational structure after giving effect to the transactions described above.

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Management of Noble Midstream Partners LP

We are managed and operated by the board of directors and executive officers of Noble Midstream GP LLC, our general partner. Noble is the sole owner of our general partner and has the right to appoint the entire board of directors of our general partner, including the independent directors appointed in accordance with the listing standards of the NYSE. Unlike shareholders in a publicly traded corporation, our unitholders will not be entitled to elect our general partner or the board of directors of our general partner. Many of the executive officers and directors of our general partner also currently serve as executive officers of Noble. Please read “Management—Directors and Executive Officers of Noble Midstream GP LLC.”

In order to maintain operational flexibility, our operations will be conducted through, and our operating assets will be owned by, our operating subsidiaries. We may, in certain circumstances, contract with third parties to provide personnel in support of our operations. However, neither we nor our operating subsidiaries will have any employees. Our general partner has the sole responsibility for providing the personnel necessary to conduct our operations, whether through directly hiring employees or by obtaining the services of personnel employed by Noble or others. In addition, pursuant to the operational services and employee secondment agreement that will be entered into at the closing of this offering, certain of Noble’s employees will be seconded to our general partner to provide management, maintenance and operational services with respect to our business under the direction and control of our general partner. All of the personnel that will conduct our business immediately following the closing of this offering will be employed or contracted by our general partner and its affiliates, including Noble, but we sometimes refer to these individuals in this prospectus as our employees because they provide services directly to us.

Principal Executive Offices and Internet Address

Our principal executive offices are located at 1001 Noble Energy Way, Houston, Texas, 77070, and our telephone number is (281) 872-3100. Following the completion of this offering, our website will be located at www.NBLMidstream.com. We expect to make our periodic reports and other information filed with or furnished to the U.S. Securities and Exchange Commission, or 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 on our website or any other website is not incorporated by reference into this prospectus and does not constitute a part of this prospectus.

Summary of Conflicts of Interest and Duties

Under our partnership agreement, our general partner has a duty to manage us in a manner it believes is in the best interests of our partnership. However, because our general partner is a wholly owned subsidiary of Noble, the officers and directors of our general partner have a duty to manage the business of our general partner in a manner that is in the best interests of Noble. As a result of this relationship, 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 Noble, on the other hand. For example, our general partner will be entitled to make determinations that affect the amount of cash distributions we make to the holders of common units, which in turn has an effect on whether Noble, as the initial holder of our incentive distribution rights, receives incentive cash distributions. In addition, our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make a distribution on the subordinated units, to make incentive distributions or to accelerate expiration of the subordination period. All of these actions are permitted under our partnership agreement and will not be a breach of any duty (fiduciary or otherwise) of our general partner. Please read “Conflicts of Interest and Duties.”

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Delaware law provides that a Delaware limited partnership may, in its partnership agreement, expand, restrict or eliminate the fiduciary duties otherwise owed by the general partner to limited partners and the partnership. As permitted by Delaware law, 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 contractual methods of resolving conflicts of interest. The effect of these provisions is to restrict the remedies available to unitholders for actions that might otherwise constitute breaches of our general partner’s fiduciary duties. Our partnership agreement also provides that affiliates of our general partner, including Noble and its affiliates, are not restricted from competing with us, and neither our general partner nor its affiliates have any obligation to present business opportunities to us except with respect to dedications contained in our commercial agreements and rights of first refusal contained in our omnibus agreement. By purchasing a common unit, the purchaser agrees to be bound by the terms of our partnership agreement, and, pursuant to the terms of our partnership agreement, each holder of common units consents to various actions and potential conflicts of interest contemplated in our partnership agreement that might otherwise be considered a breach of fiduciary or other duties under Delaware law. Please read “Conflicts of Interest and Duties—Duties of Our General Partner” and “Certain Relationships and Related Party Transactions.”

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The Offering

Common units offered to the public              common units (or              common units if the underwriters exercise in full their option to purchase additional common units from us).

Units outstanding after this offering              common units and              subordinated units, each representing an aggregate     % limited partner interest in us.

The number of common units outstanding after this offering includes              common units that are available to be issued to the underwriters pursuant to their option to purchase additional common units from us. The number of common units purchased by the underwriters pursuant to any exercise of the option will be sold to the public. 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 Noble at the expiration of the option period for no additional consideration. Accordingly, any exercise of the underwriters’ option, in whole or in part, 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 an assumed initial public offering price of $         per common unit (the mid-point of the price range set forth on the cover page of this prospectus), after deducting underwriting discounts and commissions, the structuring fee 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 to (i) make a distribution of approximately $         million to Noble and (ii) pay approximately $         million of origination fees 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 and the structuring fee. We will use any net proceeds from the exercise of the underwriters’ option to purchase additional common units to make a cash distribution to Noble.

Cash distributions We intend to make a minimum quarterly distribution of $         per unit to the extent we have sufficient cash at the end of each quarter after establishment of cash reserves and payment of fees and expenses, including payments to our general partner. We refer to this cash as “available cash.” Our ability to pay the minimum quarterly distribution is subject to various restrictions and other factors described in more detail under the caption “Cash Distribution Policy and Restrictions on Distributions.”

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We do not expect to make distributions for the period that began on                     , 2015 and ends on the day prior to the closing of this offering. We will adjust the amount of our first distribution for the period from the closing of this offering through                     , 2015 based on the number of days in that period.

In general, we will pay any cash distributions we make each quarter in the following manner:

• first, 100% to the holders of common units, until each common unit has received a minimum quarterly distribution of $         plus any arrearages from prior quarters;

• second, 100% to the holders of subordinated units, until each subordinated unit has received a minimum quarterly distribution of $         ; and

• third, 100% to all unitholders, pro rata, until each unit has received a distribution of $        .

If cash distributions to our unitholders exceed $         per unit in any quarter, Noble, as the initial holder of our incentive distribution rights, will receive increasing percentages, up to 50%, of the cash we distribute in excess of that amount. We refer to these distributions as “incentive distributions.” In certain circumstances, Noble has the right to reset the target distribution levels described above to higher levels based on our cash distributions at the time of the exercise of this reset election. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions—Incentive Distribution Rights.”

If we do not have sufficient available cash at the end of each quarter, we may, but are under no obligation to, borrow funds to pay the minimum quarterly distribution to our unitholders.

Pro forma distributable cash flow that was generated during the year ended December 31, 2014 and the twelve months ended March 31, 2015, was approximately $         million and $         million, respectively. The amount of distributable cash flow we must generate to pay the minimum quarterly 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 each of the year ended December 31, 2014 and the twelve months ended March 31, 2015, on a pro forma basis, we would not have generated sufficient distributable cash flow to pay the aggregate annualized minimum quarterly distribution on all of our common units and subordinated units. Please read “Cash Distribution Policy and Restrictions on Distributions—Unaudited Pro Forma EBITDA and Distributable Cash Flow for the Year Ended December 31, 2014 and Twelve Months Ended March 31, 2015.”

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We believe, based on our financial forecast and related assumptions included in “Cash Distribution Policy and Restrictions on Distributions—Estimated EBITDA and Distributable Cash Flow for the Twelve Months Ending September 30, 2016,” that we will generate sufficient distributable cash flow to pay the aggregate minimum quarterly distributions of $         million on all of our common units and subordinated units for the twelve months ending September 30, 2016. However, we do not have a legal obligation to pay distributions at our minimum quarterly distribution rate or at any other rate except as provided in our partnership agreement, and there is no guarantee that we will make quarterly cash distributions to our unitholders. Please read “Cash Distribution Policy and Restrictions on Distributions.”

Subordinated units Following the completion of this offering, Noble will 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, the subordinated units will not be entitled to receive any distribution until the common units have received the minimum quarterly distribution for such quarter plus any arrearages in the payment of the minimum quarterly distribution from prior quarters during the subordination period. Subordinated units will not accrue arrearages.

Conversion of subordinated units The subordination period will end on the first business day after the date that we have earned and paid distributions of at least (i) $             (the annualized minimum quarterly distribution) on each of the outstanding common units and subordinated units for each of three consecutive, non-overlapping four quarter periods ending on or after September 30, 2018 or (ii) $         (150% of the annualized minimum quarterly distribution) on each of the outstanding common units and subordinated units and the distributions on the incentive distribution rights for any four-quarter period ending on or after September 30, 2015, in each case provided there are no arrearages in payment of the minimum quarterly distributions on our common units at that time.

When the subordination period ends, each outstanding subordinated unit will convert into one common unit, and common units will no longer be entitled to arrearages. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions—Subordinated Units and Subordination Period.”

Issuance of additional partnership interests Our partnership agreement authorizes us to issue an unlimited number of additional partnership interests and options, rights, warrants and appreciation rights relating to the partnership interests for any partnership purpose at any time and from time to time to such persons for such consideration and on such terms and conditions as our general partner shall determine in its sole discretion, all without the

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approval of any limited partners. Our unitholders will not have preemptive or participation rights to purchase their pro rata share of any additional units issued. Please read “Units Eligible for Future Sale” and “Our Partnership Agreement—Issuance of Additional Partnership 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 unless such removal is both (i) for cause and (ii) approved by a vote of the holders of at least 66 ²/₃% of the outstanding units, including any units owned by our general partner and its affiliates, voting together as a single class. Following the completion of this offering, Noble will own     % of our total outstanding units on an aggregate basis (or     % of our total outstanding units on an aggregate basis if the underwriters exercise in full their option to purchase additional common units). As a result, our public unitholders will have limited ability to remove our general partner. Please read “Our Partnership Agreement—Voting Rights.”

Limited call right If at any time our general partner and its affiliates 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 (i) the average of the daily closing price of our common units over the 20 trading days preceding the date that is three business 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. Following the completion of this offering and assuming the underwriters’ option to purchase additional common units from us is not exercised, our general partner and its affiliates will own approximately     % of our common units (excluding any common units purchased by the directors, director nominee and executive officers of our general partner and certain other individuals as selected by general partner under our directed unit program). At the end of the subordination period (which could occur as early as within the quarter ending September 30, 2016), assuming no additional issuances of common units by us (other than upon the conversion of the subordinated units) and the underwriters’ option to purchase additional common units from us is not exercised, our general partner and its affiliates will own             % of our outstanding common units (excluding any common units purchased by the directors, director nominee and executive officers of our general partner, and certain other individuals as selected by our general partner under our directed unit program) and therefore would not be able to exercise the call right at that time. Please read “Our Partnership Agreement—Limited Call Right.”

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Possible redemption of ineligible holders 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 limited partners 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 the Federal Energy Regulatory Commission or similar regulatory body and (ii) nationality, citizenship or other related status does not create and is not reasonably likely to 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 limited partner interests of the class to be so redeemed multiplied by the number of limited partner interests of each such class included among the redeemable interests. For these purposes, the “current market price” means, as of any date for any class of limited partner interests, the average of the daily closing prices per limited partner interest of such class 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 “Our Partnership Agreement—Possible Redemption of Ineligible Holders.”

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 December 31, 2018, you 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 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 Federal Income Tax Consequences—Tax Consequences of Unit Ownership—Ratio of Taxable Income to Distributions.”

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

Directed unit program At our request, the underwriters have reserved for sale, at the initial public offering price, up to     % of the common units being offered by this prospectus for sale to the directors, director nominee and executive officers of our general partner and certain other individuals as selected by our general partner. We do not know if these persons will choose to purchase all or any portion of these reserved common units, but any purchases they do make will reduce the number of common units available to the general public. Please read “Underwriting—Directed Unit Program.”

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

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Summary Historical and Pro Forma Financial Data

The following table presents summary historical financial data of Noble Midstream Partners LP Predecessor, our predecessor for accounting purposes, or our Predecessor, and summary unaudited pro forma financial data of Noble Midstream Partners LP for the periods and as of the dates indicated. The following summary historical financial data of our Predecessor consists of all of the assets and operations of our Predecessor on a 100% basis. In connection with the completion of this offering, Noble will contribute to us the percentages of the midstream systems described under “Certain Relationships and Related Party Transactions—Agreements with our Affiliates in Connection with the Transactions—Contribution Agreement.” However, as required by U.S. generally accepted accounting principles, or GAAP, we will continue to consolidate 100% of the assets and operations of our development companies in our financial statements.

The summary historical financial data of our Predecessor as of and for the years ended December 31, 2014 and 2013 and as of March 31, 2015 and for the three months ended March 31, 2015 and 2014 are derived from the audited and unaudited financial statements of our 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 audited and unaudited interim and pro forma 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.”

For the years ended December 2014 and 2013, our assets were part of the integrated operations of Noble, and our Predecessor generally recognized only the costs, and not the revenues, associated with certain of the midstream services provided to Noble on an intercompany basis. Accordingly, the midstream revenues in our Predecessor’s historical combined financial statements relate only to amounts received from third parties for those services and amounts received from Noble with respect to transactions for which there were contracts. For this reason, as well as other factors described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Factors Affecting the Comparability of our Financial Results,” our future results of operations will not be comparable to our Predecessor’s historical results.

The summary unaudited pro forma financial data presented in the following table for the year ended December 31, 2014 and the three months ended March 31, 2015 are 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, 2015, and the unaudited pro forma condensed statements of operations for the year ended December 31, 2014 and the three months ended March 31, 2015 assume the offering and the related transactions occurred as of January 1, 2014. These transactions include, and the unaudited pro forma condensed financial statements give effect to, the following:

• Noble’s contribution to us of the percentages of the development companies that operate our assets as described under “Certain Relationships and Related Party Transactions—Agreements with our Affiliates in Connection with the Transactions—Contribution Agreement;”

• our entry into long-term, fixed-fee commercial agreements with Noble;

• our entry into a new $         million revolving credit facility;

• our entry into an omnibus agreement with Noble;

• the consummation of this offering and our issuance of (i)              common units to the public, (ii) a non-economic general partner interest to our general partner and (iii)              common units,              subordinated units and the incentive distribution rights to Noble; and

• the application of the net proceeds of this offering as described in “Use of Proceeds.”

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The unaudited pro forma condensed financial statements do not give effect to (i) an estimated $         million in incremental general and administrative expenses that we expect to incur annually as a result of being a publicly traded partnership or (ii) variable general and administrative costs we will incur under the omnibus agreement that we will enter into with Noble as of the closing of this offering.

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	Noble Midstream Partners LP Predecessor Historical												Noble Midstream Partners LP Pro Forma
	Year Ended December 31,						Three Months Ended March 31,						Year Ended December 31, 2014	Three Months Ended March 31, 2015
	2014			2013			2015			2014
							(unaudited)						(unaudited)
	(in thousands, except per unit data)
Statement of Operations Data
Revenues
Midstream Services—Related Party	$	2,086		$	2,169		$	12,852		$	513		$	$
Income from Investments		3,798			3,024			1,236			773
Total Revenues		5,884			5,193			14,088			1,286
Costs and Expenses
Direct Operating		8,538			2,760			2,670			2,318
Depreciation, Depletion and Amortization		11,315			3,092			1,345			2,250
General and Administrative		6,734			6,124			545			1,596
Total Operating Expense		26,587			11,976			4,560			6,164
Operating Income (Loss)		(20,703	)		(6,783	)		9,528			(4,878	)
Other Expense
Interest Expense, Net of Amount Capitalized		3,566			3,263			515			472
Total Other Expense		3,566			3,263			515			472
Income (Loss) Before Income Taxes		(24,269	)		(10,046	)		9,013			(5,350	)
Income Tax Provision (Benefit)		(9,178	)		(3,746	)		3,409			(2,023	)
Net Income (Loss) including non-controlling interests	$	(15,091	)	$	(6,300	)	$	5,604		$	(3,327	)	$	$
Net income attributable to non-controlling interests(1)
Net income attributable to Noble Midstream Partners LP
Net income per limited partner unit (basic and diluted):
Common units
Subordinated units
Balance Sheet Data (at period end):
Total Property, Plant and Equipment, Net	$	195,513		$	127,504		$	220,361					$	$
Total Assets		216,512			139,883			258,363
Net Parent Investment/Partners’ Capital		213,673			137,179			235,812
Statement of Cash Flows Data
Net Cash Provided by (Used in) Operating Activities	$	(12,534	)	$	(6,935	)	$	8,292		$	(2,994	)	$	$
Net Cash Used in Investing Activities		(79,904	)		(95,586	)		(19,884	)		(15,588	)
Net Cash Provided by Financing Activities		92,438			102,521			21,522			18,582
Other Data
Capital expenditures(2)	$	80,466		$	96,318		$	19,371		$	15,702		$	$
EBITDA(3)		(9,388	)		(3,691	)		10,873			(2,628	)
EBITDA attributable to Noble Midstream Partners LP(3)

(1) Represents     %,     %,     %,     % and     % non-controlling interests in the development companies that hold our operating assets that have been retained by Noble as described under “Certain Relationships and Related Party Transactions—Agreements with our Affiliates in Connection with the Transactions—Contribution Agreement.”

(2) Represents additions to property, plant and equipment within the combined statement of cash flows.

(3) For our definition of the non-GAAP financial measure of EBITDA and a reconciliation of EBITDA to our most directly comparable financial measures calculated and presented in accordance with GAAP, please read “Selected Historical and Pro Forma Financial Data—Non-GAAP Financial Measure.”

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RISK FACTORS

Limited partner interests are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. You should carefully consider the following risk factors together with all of the other information included in this prospectus, including the matters addressed under “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, cash flows and ability to make cash distributions could be materially adversely affected. In that case, we may not be able to pay the minimum quarterly distribution on our common units, the trading price of our common units could decline and you could lose all or part of your investment.

Risks Related to Our Business

We derive substantially all of our revenue from Noble. If Noble changes its business strategy, alters its current drilling and development plan on our dedicated acreage, or otherwise significantly reduces the volumes of crude oil, natural gas, saltwater or fresh water with respect to which we perform midstream services, our revenue would decline and our business, financial condition, results of operations, cash flows and ability to make distributions to our unitholders would be materially and adversely affected.

All of our commercial agreements are with Noble or its affiliates. Accordingly, because we expect to initially derive substantially all of our revenue from our commercial agreements with Noble, we are subject to the operational and business risks of Noble, the most significant of which include the following:

• a reduction in or slowing of Noble’s drilling and development plan on our dedicated acreage, which would directly and adversely impact demand for our midstream services;

• the volatility of crude oil, natural gas and NGL prices, which could have a negative effect on Noble’s drilling and development plan on our dedicated acreage or Noble’s ability to finance its operations and drilling and completion costs on our dedicated acreage;

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

• drilling and operating risks, including potential environmental liabilities, associated with Noble’s operations on our dedicated acreage;

• downstream processing and transportation capacity constraints and interruptions, including the failure of Noble to have sufficient contracted processing or transportation capacity; and

• adverse effects of increased or changed governmental and environmental regulation.

In addition, we are indirectly subject to the business risks of Noble generally and other factors, including, among others:

• Noble’s financial condition, credit ratings, leverage, market reputation, liquidity and cash flows;

• Noble’s ability to maintain or replace its reserves;

• adverse effects of governmental and environmental regulation on Noble’s upstream operations; and

• losses from pending or future litigation.

Further, we have no control over Noble’s business decisions and operations, and Noble is under no obligation to adopt a business strategy that is favorable to us. Thus, we are subject to the risk of non-payment or non-performance by Noble, including with respect to our midstream services agreements, which do not contain minimum volume commitments. The number of drilling rigs that Noble is operating in the DJ Basin has

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decreased from nine rigs in the fourth quarter of 2014 to four rigs in the first quarter of 2015. A further decrease in the number of drilling rigs that Noble operates on our dedicated acreage could result in lower throughput on our midstream infrastructure. Furthermore, we cannot predict the extent to which Noble’s businesses would be impacted if conditions in the energy industry were to deteriorate nor can we estimate the impact such conditions would have on Noble’s ability to execute its drilling and development plan on our dedicated acreage or to perform under our midstream services agreements. Any material non-payment or non-performance by Noble under our midstream services agreements would have a significant adverse impact on our business, financial condition, results of operations and cash flows and could therefore materially adversely affect our ability to make cash distributions to our unitholders at the minimum quarterly distribution rate or at all. Each of our midstream services agreements has an initial term of 15 years, and there is no guarantee that we will be able to renew or replace these agreements on equal or better terms, or at all, upon their expiration. Our ability to renew or replace our midstream services agreements following their expiration at rates sufficient to maintain our current revenues and cash flows could be adversely affected by activities beyond our control, including the activities of our competitors and Noble.

On a pro forma basis, we would not have generated sufficient distributable cash flow to make the payment of the aggregate annualized minimum quarterly distribution on all of our units for the year ended December 31, 2014 or the twelve months ended March 31, 2015.

We must generate approximately $         million of distributable cash flow to make 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 flow generated during each of the year ended December 31, 2014 and the twelve months ended March 31, 2015 would not have been sufficient to pay the full minimum quarterly distribution on our common units and subordinated units during those periods. Specifically, the amount of pro forma distributable cash flow generated during the year ended December 31, 2014 would have been sufficient to make a distribution of approximately $         per common unit per quarter (approximately $         per common unit on an annualized basis), or approximately     % of the minimum quarterly distribution, and would not have made any distributions on our subordinated units, and the amount of pro forma distributable cash flow generated during the twelve months ended March 31, 2015 would have been sufficient to support a distribution of $         per common unit per quarter ($         per common unit on an annualized basis), or     % of the minimum quarterly distribution, and would have been sufficient to make a distribution of approximately $         per subordinated unit per quarter (approximately $         per subordinated unit on an annualized basis), or approximately     % of the minimum quarterly distribution. 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, 2014 and the twelve months ended March 31, 2015, please read “Cash Distribution Policy and Restrictions on Distributions.” If we are unable to generate sufficient distributable cash flow in future periods, we may not be able to make 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.

We may not generate sufficient distributable cash flow to make the payment of the minimum quarterly distribution to our unitholders.

In order to make the payment of the minimum quarterly distribution of $         per unit per quarter, or $         per unit on an annualized basis, we must generate distributable cash flow 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 the completion of this offering. We may not generate sufficient distributable cash flow to make the payment of the minimum quarterly distribution to our unitholders.

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:

• the volumes of natural gas we gather, the volumes of crude oil we gather and treat, the volumes of saltwater we collect, clean and recycle or dispose of and the volumes of fresh water we distribute and store;

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• market prices of crude oil, natural gas and NGLs and their effect on Noble’s drilling and development plan on our dedicated acreage and the volumes of hydrocarbons that are produced on our dedicated acreage and for which we provide midstream services;

• Noble’s ability to fund its drilling and development plan on our dedicated acreage;

• downstream processing and transportation capacity constraints and interruptions, including the failure of Noble to have sufficient contracted processing or transportation capacity;

• the levels of our operating expenses, maintenance expenses and general and administrative expenses;

• regulatory action affecting: (i) the supply of, or demand for, crude oil, natural gas, NGLs and water, (ii) the rates we can charge for our midstream services, (iii) the terms upon which we are able to contract to provide our midstream services, (iv) our existing gathering and other commercial agreements or (v) our operating costs or our operating flexibility;

• the rates we charge third parties, if any, for our midstream services;

• prevailing economic conditions; and

• adverse weather conditions.

In addition, the actual amount of distributable cash flow that we generate will also depend on other factors, some of which are beyond our control, including:

• the level and timing of our capital expenditures;

• our debt service requirements and other liabilities;

• our ability to borrow under our debt agreements to fund our capital expenditures and operating expenditures and to pay distributions;

• fluctuations in our working capital needs;

• restrictions on distributions contained in any of our debt agreements;

• the cost of acquisitions, if any;

• the fees and expenses of our general partner and its affiliates (including Noble) that we are required to reimburse;

• the amount of cash reserves established by our general partner; and

• other business risks affecting our cash levels.

The assumptions underlying the forecast of distributable cash flow that we include in “Cash Distribution Policy and Restrictions on Distributions” are inherently uncertain and subject to significant business, economic, financial, regulatory and competitive risks that could cause our actual distributable cash flow to differ materially from our forecast.

The forecast of distributable cash flow set forth in “Cash Distribution Policy and Restrictions on Distributions” includes our forecast of our results of operations and distributable cash flow for the twelve months ending September 30, 2016. 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 “Cash Distribution Policy and Restrictions on Distributions.” Our financial forecast has been prepared by management, and we have neither received nor requested an opinion or report on it from our or any other independent auditor.

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The demand for our midstream services, and therefore our cash flow, is affected by crude oil and natural gas prices, which fluctuate based on factors that are out of our control.

The level and pace of Noble’s exploration and production activity is, in part, driven by commodity prices for crude oil and natural gas. Because Noble’s demand for our midstream services is tied to its production levels, we are also indirectly exposed to commodity price risk. Beginning in the fourth quarter of 2014, crude oil and natural gas prices significantly declined and continued to decline during the first quarter of 2015. High and low daily average prices for monthly contracts for crude oil and high and low contract expirations prices for natural gas during the year ended December 31, 2014 and the three months ended March 31, 2015 were as follows:

	Daily Average Settlement Price for Prompt Month Contracts
	High		Low
Year Ended December 31, 2014
NYMEX
Crude Oil—WTI (Per Bbl)	$	105.15	$	59.29
Natural Gas—Henry Hub (Per MMBtu)		5.56		3.73
Three Months Ended June 30, 2015
NYMEX
Crude Oil—WTI (Per Bbl)	$	61.43	$	43.46
Natural Gas—Henry Hub (Per MMBtu)		3.23		2.49

Noble has lowered its rig count in the DJ Basin for 2015 as compared to 2014, partially as a result of the decline in crude oil and natural gas prices. When combined with a reduction of cash flow resulting from lower commodity prices, a reduction in Noble’s available capital and lack of availability of debt or equity financing could result in a significant reduction of Noble’s spending for crude oil and natural gas drilling and development activity, which could result in a lower utilization rate of our midstream systems. If we are not able to obtain new supplies of crude oil and natural gas to replace the declines resulting from reductions in drilling and development activity, the utilization rates of our midstream assets will decline, which could have a material adverse effect on our business, results of operations, financial position and cash flows and our ability to make cash distributions.

Because of the natural decline in production from existing wells, our success, in part, depends on our ability to maintain or increase hydrocarbon throughput volumes on our midstream systems, which depends on Noble’s levels of development and completion activity on our dedicated acreage.

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 order to maintain or increase throughput levels on our midstream systems, we must obtain production from wells completed by Noble on acreage dedicated to our midstream systems or third parties in our areas of operation.

We have no control over Noble’s or other producers’ levels 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 Noble or other producers or their exploration and development decisions, which may be affected by, among other things:

• the availability and cost of capital;

• prevailing and projected crude oil, natural gas and NGL prices;

• demand for crude oil, natural gas and NGLs;

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• levels of reserves;

• geologic considerations;

• changes in the strategic importance Noble assigns to development in the DJ Basin as opposed to its other operations, which could adversely affect the financial and operational resources Noble is willing to devote to development of our dedicated acreage;

• increased levels of taxation related to the exploration and production of crude oil, natural gas and NGLs in our areas of operation;

• environmental or other governmental regulations, including the availability of drilling permits and the regulation of hydraulic fracturing; and

• the costs of producing crude oil, natural gas and NGLs and the availability and costs of drilling rigs and other equipment.

Due to these and other factors, even if reserves are known to exist in areas served by our midstream assets, producers, including Noble, may choose not to develop those reserves. If producers choose not to develop their reserves, or they choose to slow their development rate, in our areas of operation, utilization of our midstream systems will be below anticipated levels. Our inability to provide increased services resulting from reductions in development activity, coupled with the natural decline in production from our current dedicated acreage, would result in our inability to maintain the then-current levels of utilization of our midstream assets, which could materially adversely affect our business, financial condition, results of operations, cash flows and ability to make cash distributions.

If Noble does not maintain its drilling activities on our dedicated acreage, the demand for our fresh water services could be reduced, which could have a material adverse effect on our results of operations, cash flows and ability to make distributions to our unitholders.

The fresh water services we provide to Noble assist in Noble’s drilling activities. If Noble does not maintain its drilling activities on our dedicated acreage, its demand for our fresh water services will be reduced regardless of whether we continue to provide our other midstream services on Noble’s production. If the demand for our fresh water services declines for this or any other reason, our results of operations, cash flows and ability to make distributions to our unitholders could be materially adversely affected.

Substantially all of our assets are controlling ownership interests in our operating subsidiaries. Because our interests in our operating subsidiaries represent almost all of our cash-generating assets, our cash flow will depend entirely on the performance of our operating subsidiaries 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 operating subsidiaries. Therefore, our ability to make quarterly distributions to our unitholders will be almost entirely dependent upon the performance of our operating subsidiaries and their ability to distribute funds to us. We are the sole member of the general partner of each of our operating subsidiaries, and we control and manage our operating subsidiaries through our ownership of our operating subsidiaries’ respective general partners.

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

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The amount of cash each operating company generates from its operations will fluctuate from quarter to quarter based on events and circumstances and the actual amount of cash each operating company will have available for distribution to its partners, including us, also will depend on certain factors. For a description of the events, circumstances and factors that may affect the cash distributions from our operating subsidiaries please read “—We may not generate sufficient distributable cash flow to make the payment of the minimum quarterly distribution to our unitholders.”

Our midstream assets are currently exclusively located in the DJ Basin in Colorado, making us vulnerable to risks associated with operating in a single geographic area.

Our midstream assets are currently located exclusively in the DJ Basin in Colorado. As a result of this concentration, we will 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, water shortages or other drought related conditions or interruption of the processing or transportation of crude oil and natural gas. If any of these factors were to impact the DJ Basin more than other producing regions, our business, financial condition, results of operations and ability to make cash distributions could be adversely affected relative to other midstream companies that have a more geographically diversified asset portfolio.

We cannot predict the rate at which Noble will develop acreage that is dedicated to us or the areas it will decide to develop.

Our acreage dedication covers midstream services in a number of areas that are at the early stages of development or in areas that Noble is still determining whether to develop. In addition, Noble owns acreage in areas that are not dedicated to us. We cannot predict which of these areas Noble will determine to develop and at what time. Noble 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. Noble’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.

While we have been granted a right of first refusal to provide midstream services on acreage that Noble recently acquired in the Eagle Ford Shale in south Texas and the Permian Basin in west Texas, portions of this acreage are subject to preexisting dedications that may require Noble to use third parties for midstream services.

On July 20, 2015, Noble acquired approximately 50,000 net acres in the Eagle Ford Shale in south Texas and 56,000 net acres in the Permian Basin in west Texas from Rosetta Resources Inc. Although Noble has granted us a ROFR to provide midstream services on this newly acquired acreage, portions of this acreage are subject to preexisting dedications that require Noble to use third parties for midstream services, and, as a result, Noble may be precluded from offering us the opportunity to provide midstream services on this acreage. Due to the large amount of the acreage acquired, we do not know the extent, if any, of the benefit we may be able to ultimately derive from Noble’s acreage acquisition and granting us this ROFR.

We may not be able to economically accept an offer from Noble for us to provide services with respect to which we have a right of first refusal.

Noble is required to offer us, prior to offering such opportunity to a third party, the opportunity to provide midstream services on upstream acreage or midstream systems that Noble currently owns or in the future acquires or develops that is not subject to a third-party dedication. We can make no assurances that the terms at which Noble offers us the opportunity to provide these services will be acceptable to us. Furthermore, another midstream service provider may be willing to accept an offer from Noble that we are unwilling to accept. Our determination to refuse an offer Noble makes to us could adversely affect our growth strategy or our ability to maintain or increase our cash distribution level.

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We may be unable to grow by acquiring the non-controlling interests in our development companies owned by Noble or midstream assets retained, acquired or developed by Noble, which could limit our ability to increase our distributable cash flow.

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 flow. Part of the acquisition component of our growth strategy is based upon our expectation of future divestitures by Noble to us of retained, acquired or developed midstream assets and portions of its retained, non-controlling interests in our development companies. We have only a ROFR pursuant to our omnibus agreement that allows us to purchase, if Noble elects to sell, the non-controlling interests in our development companies retained by Noble and midstream assets retained, acquired or developed by Noble after the completion of this offering. Noble is under no obligation to offer to sell us additional interests or assets, we are under no obligation to buy any additional interests or assets from Noble and we do not know when or if Noble will make any offers to sell interests or assets to us. We may never purchase all or any portion of the non-controlling interests in our development companies or any of Noble’s retained, acquired or developed midstream assets for several reasons, including the following:

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

• we may not accept offers for these non-controlling interests or assets;

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

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

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

We do not know when or if all or any portion of non-controlling interests or assets will be offered to us for purchase, 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 development companies or assets. Furthermore, if Noble reduces its ownership interest in us, it may be less willing to sell to us its retained non-controlling interests in our development companies or its retained assets. In addition, except for our rights of first refusal, there are no restrictions on Noble’s ability to transfer its non-controlling interests in our development companies or its retained 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 development companies held by Noble or midstream assets from Noble, our ability to grow our business and increase our cash distributions to our unitholders may be significantly limited.

We may not be able to attract dedications of third-party volumes, in part because our industry is highly competitive, which could limit our ability to grow and increase our dependence on Noble.

Part of our long-term growth strategy includes diversifying our customer base by identifying opportunities to offer services to third parties in our areas of operation. To date and over the near term, substantially all of our revenues have been and will be earned from Noble relating to its operated wells on our dedicated acreage. 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. Any lack of available capacity on our systems for third-party volumes will detrimentally affect our ability to compete effectively with third-party systems for crude oil and natural gas from reserves associated with acreage other than our then-current dedicated acreage. In addition,

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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.

Our efforts to attract new third parties as customers may be adversely affected by our relationship with Noble and the fact that a substantial majority of the capacity of our midstream systems will be necessary to service its production on our dedicated acreage and our desire to provide services pursuant to fee-based agreements. As a result, we may not have the capacity to provide services to third parties and/or potential third-party customers may prefer to obtain services pursuant to other forms of contractual arrangements under which we would be required to assume direct commodity exposure. In addition, 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. All of these competitive pressures could have a material adverse effect on our business, results of operations, financial condition, cash flows and ability to make cash distributions to our unitholders.

To maintain and grow our business, we will be required to make substantial capital expenditures. 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 maintain and grow our business, we will need to make substantial capital expenditures to fund our share of growth capital expenditures associated with our operating interests in our development companies, or to purchase or construct new midstream systems. If we do not make sufficient or effective capital expenditures, we will be unable to maintain and grow our business and, as a result, we may be unable to maintain or raise the level of our future cash distributions over the long term. To fund our capital expenditures, we will be required to use cash from our operations, incur debt or sell additional common units or other equity securities. Using cash from our operations will reduce cash available for distribution to our unitholders. Our ability to obtain bank financing or our ability to access the capital markets for future equity or debt offerings may be limited by our 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. Also, due to our relationship with Noble, 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 the financial condition of Noble or adverse changes in Noble’s credit ratings. Any material limitation on our ability to access capital as a result of such adverse changes to Noble 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 affecting Noble 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, or could also prevent us from engaging in certain transactions that might otherwise be considered beneficial to us. We will also rely on Noble to make its portion of capital expenditures on our assets, and to the extent that Noble is unable or unwilling to make these capital expenditures, we may not be able to grow at our expected rate or at all.

Even if we are successful in obtaining the necessary funds to support our growth plan, 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 then prevailing distribution rate. While we have historically received funding from Noble, none of Noble, our general partner or any of their respective affiliates is committed to providing any direct or indirect financial support to fund our growth.

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

The amount of cash we have available for distribution depends primarily upon our cash flow and not solely on our profitability, which will be affected by non-cash items. As a result, we may make cash distributions

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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.

Increased competition from other companies that provide midstream services, or from alternative fuel sources, 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 systems compete for third-party customers primarily with other crude oil and natural gas gathering systems and fresh and saltwater service providers. Some of our competitors have greater financial resources and may now, or in the future, have access to greater supplies of crude oil and natural gas than we do. Some of these competitors may expand or construct gathering systems that would create additional competition for the services we would provide to third-party customers. In addition, potential third-party customers may develop their own gathering systems instead of using ours. Moreover, Noble and its affiliates are not limited in their ability to compete with us outside of our dedicated area. See “Conflicts of Interest and Duties.”

Further, hydrocarbon fuels compete with other forms of energy available to end-users, including electricity and coal. Increased demand for such other forms of energy at the expense of hydrocarbons could lead to a reduction in demand for our services.

All of these competitive pressures could make it more difficult for us to retain our existing customers 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 natural gas in the markets served by our systems, 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 natural gas.

Our construction of new midstream 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 unitholders.

The construction of additions or modifications to our existing systems involves numerous regulatory, environmental, political and legal uncertainties beyond our control, may require the expenditure of significant amounts of capital, and we may not be able to construct in certain locations due to set back requirements. 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.

Our revenues may not increase immediately (or at all) upon the expenditure of funds on a particular project. For instance, if we build additional gathering assets, 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 or at all. Additionally we may construct facilities to capture anticipated future production growth in an area where such growth does not materialize. As a result, new midstream assets may not be able to attract enough throughput to achieve our expected investment return, which could adversely affect our business, financial condition, results of operations, cash flows and ability to make cash distributions.

The construction of additions to our existing assets may require us to obtain new rights-of-way, leases or other surface use agreements prior to constructing new pipelines or facilities. We may be unable to timely obtain such rights-of-way to connect new crude oil, natural gas and water sources to our existing infrastructure 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, leases or other agreements. If the cost of renewing or obtaining new agreements increases, our cash flows could be adversely affected.

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We are subject to regulation by multiple governmental agencies, which could adversely impact our business, results of operations and financial condition.

We are subject to regulation by multiple federal, state and local governmental agencies. Proposals and proceedings that affect the midstream industry are regularly considered by Congress, as well as by state legislatures and federal and state regulatory commissions, agencies and courts. We cannot predict when or whether any such proposals may become effective or the magnitude of the impact changes in laws and regulations may have on our business. However, additions to the regulatory burden on our industry generally increase our cost of doing business and affect our profitability.

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

Currently, only the crude oil gathering system servicing the East Pony IDP 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 the FERC, unless such rate requirements are waived. We have applied for a waiver of the FERC’s rate and tariff requirements. If the FERC denies our waiver request, we will be required to file rates and a tariff at the FERC for the crude oil gathering system servicing the East Pony IDP. These rates will need to be just and reasonable and not unduly discriminatory. If we propose new or changed rates, the FERC or interested persons may challenge those rates and the FERC is authorized to suspend the effectiveness of such rates for up to seven months and to investigate such rates. If, upon completion of an investigation, the FERC finds that the proposed rate is unjust or unreasonable, it is authorized to require the carrier to refund revenues in excess of the prior tariff during the term of the investigation. The FERC also may investigate, upon complaint or on its own motion, rates that are already in effect and may order a carrier to change its rates prospectively. Upon an appropriate showing, a shipper may obtain reparations for damages sustained for a period of up to two years prior to the filing of a complaint. A successful challenge of our rates could adversely affect our revenues.

The FERC uses prescribed rate methodologies for approving regulated tariff rate changes for interstate crude oil pipelines. The FERC’s indexing methodology currently allows a pipeline to increase its rates by a percentage linked to the U.S. Producer Price Index for Finished Goods, or PPI. As an alternative to this indexing methodology, we may also choose to support our rates based on a cost-of-service methodology, or by obtaining advance approval to charge “market-based rates,” or by charging “settlement rates” agreed to by all affected shippers. These methodologies may limit our ability to set rates based on our actual costs or may delay the use of rates reflecting increased costs. Changes in the FERC’s methodology for approving rates, or challenges to our application of that methodology, could adversely affect us. Adverse decisions by the FERC in approving our regulated rates could adversely affect our cash flow.

We may also be required to respond to requests for information from government agencies, including compliance audits conducted by the FERC.

Federal and state legislative and regulatory initiatives relating to pipeline safety that require the use of new or more stringent safety controls or result in more stringent enforcement of applicable legal requirements could subject us to increased capital costs, operational delays and costs of operation.

The Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, the Pipeline Safety and Job Creations Act, is the most recent federal legislation to amend the Natural Gas Pipeline Safety Act of 1968, as amended, or NGPSA, and the Hazardous Liquids Pipeline Safety Act of 1979, as amended, or HLPSA, pipeline safety laws, requiring increased safety measures for natural gas and hazardous liquids pipelines. Among other things, the Pipeline Safety and Job Creations Act directs the Secretary of Transportation to promulgate regulations relating to expanded integrity management requirements, automatic or remote-controlled valve use, excess flow valve use, leak detection system installation, material strength testing, and verification of the maximum allowable pressure of certain pipelines. The Pipeline Safety and Job Creations Act also increases the maximum penalty for violation of pipeline safety regulations from $100,000 to $200,000 per violation per day of

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violation and from $1.0 million to $2.0 million for a related series of violations. The safety enhancement requirements and other provisions of the Pipeline Safety and Job Creations Act as well as any implementation of Pipeline and Hazardous Materials Safety Administration, or PHMSA, rules thereunder could require us to install new or modified safety controls, pursue additional capital projects, or conduct maintenance programs on an accelerated basis, any or all of which tasks could result in our incurring increased operating costs that could have a material adverse effect on our results of operations or financial position.

Our ownership interest in White Cliffs LLC could require us to make capital contributions from time to time, which could have a material adverse effect on our business, financial condition, results of operations, cash flows and ability to make distributions to our unitholders.

We currently own a 3.33% non-operating interest in White Cliffs LLC. Because we do not operate or control White Cliffs LLC, we do not have control over decisions to make maintenance and growth capital expenditures on the White Cliffs Pipeline. Furthermore, White Cliffs LLC is subject to many of the same environmental and regulatory risks that our assets are subject to, including regulation by the FERC. To the extent that the operator of White Cliffs LLC decides to make capital expenditures on White Cliffs LLC or White Cliffs LLC becomes subject to regulatory assessments, we could be required to contribute additional capital to White Cliffs LLC, which could have a material adverse effect on our business, financial condition, results of operations, cash flows and ability to make distributions to our unitholders.

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, the majority 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 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 agreements for our midstream services with third parties or with Noble.

We currently generate all of our revenues pursuant to fee-based gathering 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, Noble is exposed to commodity price risk, and extended reduction in commodity prices could reduce the production volumes available for our midstream services in the future below expected levels. Although we intend to enter into fee-based gathering agreements with existing or new customers in the future, our efforts to negotiate such terms may not be successful.

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 prior to or in connection with the closing of this offering. We expect our new revolving credit facility will limit our ability to, among other things:

• incur or guarantee additional debt;

• redeem or repurchase units or make distributions under certain circumstances;

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• make certain investments and acquisitions;

• incur certain liens or permit them to exist;

• enter into certain types of transactions with affiliates;

• merge or consolidate with another company; and

• transfer, sell or otherwise dispose of assets.

We expect our new revolving credit facility will also contain covenants requiring us to maintain certain financial ratios.

The provisions of our new revolving credit facility may affect our ability to obtain future financing and to 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—Capital Resources and Liquidity.”

Increased regulation of hydraulic fracturing could result in reductions or delays in crude oil and natural gas production by our customers, which could reduce the throughput on our gathering and other midstream systems, which could adversely impact our revenues.

We do not conduct hydraulic fracturing operations, but substantially all of Noble’s crude oil and natural gas production on our dedicated acreage is developed from unconventional sources, such as shales, that require hydraulic fracturing as part of the completion process. Hydraulic fracturing is a well stimulation process that utilizes large volumes of water and sand combined with fracturing chemical additives that are pumped at high pressure to crack open previously impenetrable rock to release hydrocarbons. Hydraulic fracturing is typically regulated by state oil and gas commissions and similar agencies. Some states, including those in which we operate, have adopted, and other states are considering adopting, regulations that could impose more stringent disclosure or well construction requirements on hydraulic fracturing operations, or otherwise seek to ban some or all of these activities. Recently, however, several federal agencies have asserted jurisdiction over the process. For example, the Bureau of Land Management finalized rules in March 2015 that impose new requirements related to disclosure, well bore integrity, and water management on hydraulic fracturing on federal lands. The U.S. District Court of Wyoming has temporarily stayed implementation of this rule. A final decision is pending, however. In addition, the Environmental Protection Agency, or EPA, has moved forward with various regulatory actions, including the issuance of new regulations requiring green completions for hydraulically fractured wells, emission requirements for certain midstream equipment, and an Advanced Notice of Proposed Rulemaking seeking comment on its intent to develop regulations under the Toxic Substances and Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing. In addition, in April 2015, the EPA proposed to prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants. Certain environmental groups have also suggested that additional laws may be needed to more closely and uniformly regulate the hydraulic fracturing process; and legislation has been proposed by some members of Congress to provide for such regulation. We cannot predict whether any such legislation will be enacted and if so, what its provisions would be. Additional levels of regulation and permits required through the adoption of new laws and regulations at the federal, state or local level could lead to delays, increased operating costs and process prohibitions that could reduce the volumes of crude oil and natural gas that move through our gathering systems and decrease demand for our water services, which in turn could materially adversely impact our revenues.

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We, Noble or any third-party customers may incur significant liability under, or costs and expenditures to comply with, environmental and worker health and safety regulations, which are complex and subject to frequent change.

As an owner and operator of gathering systems, we are subject to various stringent federal, state and local laws and regulations relating to the discharge of materials into, and protection of, the environment and worker health and safety. 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 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 imposition of specific standards addressing worker protection, and the imposition of substantial liabilities and remedial obligations for pollution or contamination resulting from our and our customers’ operations. Failure to comply with these laws, regulations and permits may result in joint and several or strict liability or the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations or the issuance of injunctions limiting or preventing some or all of our operations. Private parties, including the owners of the properties through which our gathering systems pass, may also have the right to pursue legal actions to enforce compliance, as well as to seek damages for non-compliance, with environmental laws and regulations or for personal injury or property damage. We may not be able to recover all or any of these costs from insurance. In addition, we may 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 the amount of cash we have available for distribution. There is no assurance that changes in or additions to public policy regarding the protection of the environment and worker health and safety will not have a significant impact on our operations and the amount of cash we have available for distribution.

Our operations also pose risks of environmental liability due to leakage, migration, releases or spills 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 hazardous substances, hydrocarbons or solid wastes have been stored or released. We may be required to remediate contaminated properties currently or formerly operated by us 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 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 crude oil and natural gas industry could continue, potentially resulting in increased costs of doing business and consequently affecting the amount of cash we have available for distribution. Please read “Business—Regulation of Operations.”

Climate change laws and regulations restricting emissions of greenhouse gases could result in increased operating costs and reduced demand for the crude oil and natural gas that we gather while potential physical effects of climate change could disrupt Noble’s and our other customers’ production and cause us to incur significant costs in preparing for or responding to those effects.

In response to findings that emissions of carbon dioxide, methane and other greenhouse gases, or GHGs, present an endangerment to public health and the environment, the EPA has adopted regulations under existing provisions of the Clean Air Act, or CAA, that, among other things, establish Prevention of Significant Deterioration, or PSD, construction and Title V operating permit reviews for certain large stationary sources that emit GHGs. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards that will be established by the states or, in some cases, by the EPA on a case-by-case basis. These EPA rulemakings could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources. In addition, the EPA has adopted rules requiring the

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monitoring and reporting of GHG emissions from specified onshore crude oil and natural gas production sources in the U.S. on an annual basis.

While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking or reducing GHG emissions.

In addition, the EPA and states continue the development of regulations to further address the potential impacts of climate change. For example in February 2015, Colorado’s Air Quality Control Commission approved comprehensive changes to rules governing crude oil and natural gas activities in the state, including the nation’s first-ever regulations designed to detect and reduce methane emissions. The EPA is also acting to increase the requirements associated with methane releases from crude oil and natural gas activities. In 2014, the EPA released a set of five white papers analyzing methane emissions from the industry. As part of the Administration’s efforts to reduce methane emissions from the crude oil and natural gas sector by up to 45 percent from 2012 levels by 2025, the Obama Administration announced in January 2015 that the EPA is expected to propose in the summer of 2015, and to finalize in 2016, new regulations that will set methane emission standards for new and modified crude oil and natural gas facilities. The Bureau of Land Management is expected to address methane emissions from crude oil and natural gas sources in 2015 as well.

Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations. Substantial limitations on GHG emissions could also adversely affect demand for the crude oil and natural gas we gather. 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 any such effects were to occur, they could have an adverse effect on Noble’s exploration and production operations. Please read “Business—Regulation of Operations.”

Certain plant or animal species are or could be designated as endangered or threatened, which could have a material impact on our and Noble’s operations.

The federal Endangered Species Act, or ESA, restricts activities that may affect endangered or threatened species or their habitats. Many states have analogous laws designed to protect endangered or threatened species. Such protections, and the designation of previously undesignated species under such laws, may affect our and Noble’s operations by imposing additional costs, approvals and accompanying delays.

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 cash we have available for distribution.

Although the 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 the FERC has used to determine that a pipeline is a gathering pipeline and are 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 the 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 the FERC, the courts or Congress. If the FERC were to consider the status of an individual facility and determine that the facility or services provided by it are not

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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 the FERC under the NGA or the Natural Gas Policy Act, or NGPA. 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 the FERC.

Our natural gas gathering pipelines are exempt from the jurisdiction of the FERC under the NGA, but FERC regulation may indirectly impact gathering services. The 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, the FERC has pursued pro-competitive policies in its regulation of interstate crude oil and natural gas pipelines. However, we cannot assure you that the FERC will continue to pursue this approach as it considers matters such as pipeline rates and rules and policies that may indirectly affect the 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 the 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 the 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 the 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 the FERC’s jurisdiction. If it was determined that more or all of our crude oil gathering pipeline systems are subject to the 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.

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 make cash distributions and, accordingly, the market price for our common units.

Our operations are subject to all of the hazards inherent in the gathering of crude oil, natural gas and saltwater and the delivery and storage of fresh water, including:

• damage to pipelines, centralized gathering facilities, pump stations, related equipment and surrounding properties caused by design, installation, construction materials or operational flaws, natural disasters, acts of terrorism or acts of third parties;

• leaks of crude oil, natural gas or NGLs or losses of crude oil, natural gas or NGLs as a result of the malfunction of, or other disruptions associated with, equipment or facilities;

• fires, ruptures and explosions; and

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• other hazards that could also result in personal injury and loss of life, pollution and suspension of operations.

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

• injury or loss of life;

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

• pollution and other environmental damage;

• regulatory investigations and penalties;

• suspension of our operations; and

• repair and remediation costs.

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

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

We do not own in fee any of the land on which our midstream systems have been constructed. Our only interests in these properties are rights granted under surface use agreements, rights-of-way, surface leases or other easement rights. 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, surface leases or other easement rights or if such usage rights lapse or terminate. We may obtain the rights to construct and operate our pipelines 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 rights-of-way, surface leases or other easement rights or otherwise, could have a material adverse effect on our business, financial condition, results of operations, cash flows and ability to make cash distributions.

A shortage of equipment and skilled labor in the DJ Basin 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.

Our gathering and other midstream services require special equipment and laborers who are 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 business and results of operations could be materially and adversely affected.

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

We depend on the services of a relatively small group of our general partner’s 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. The loss of the services of our general partner’s senior management or technical personnel, including Christian S. Kendall, our Chief Executive Officer,             , our             ,             , our             ,             , our             , and             , our             , could have a material adverse effect on our business, financial condition, results of operations, cash flows and ability to make cash distributions.

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We do not have any officers or employees and rely on officers of our general partner and employees of Noble.

We are managed and operated by the board of directors and executive officers of our general partner. Our general partner has no employees and relies on the employees of Noble to conduct our business and activities.

Noble conducts businesses and activities of its 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 both our general partner and Noble. If our general partner and the officers and employees of Noble do not devote sufficient attention to the management and operation of our business and activities, our business, financial condition, results of operations, cash flows and ability to make cash distributions could be materially adversely affected.

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

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

• our ability to obtain additional financing, if necessary, for working capital, capital expenditures (including building additional gathering pipelines needed for required connections and building additional centralized gathering facilities pursuant to our gathering agreements) or other purposes may be impaired or such financing may not be available on favorable terms;

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

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

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

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

Increases in interest rates could adversely affect our business.

We will have 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. Assuming our average debt level of $         million, comprised of funds drawn on our new revolving credit facility, an increase of one percentage point in the interest rates will result in an increase in annual interest expense of $         million. 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.

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 Noble 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

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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.

Risks Inherent in an Investment in Us

Our general partner and its affiliates, including Noble, have conflicts of interest with us and limited fiduciary duties to us and our unitholders, and they may favor their own interests to our detriment and that of our unitholders. Additionally, we have no control over the business decisions and operations of Noble, and Noble is under no obligation to adopt a business strategy that favors us.

Following the completion of this offering, Noble will directly 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). In addition, Noble will own and control our general partner. Although our general partner has a duty to manage us in a manner that is in the best interests of our partnership and our unitholders, the directors and officers of our general partner also have a duty to manage our general partner in a manner that is in the best interests of its owner, Noble. Conflicts of interest may arise between Noble and its affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts, the general partner may favor its own interests and the interests of its affiliates, including Noble, over the interests of our common unitholders. These conflicts include, among others, the following situations:

• neither our partnership agreement nor any other agreement requires Noble to pursue a business strategy that favors us or utilizes our assets, which could involve decisions by Noble to increase or decrease crude oil or natural gas production on our dedicated acreage, pursue and grow particular markets or undertake acquisition opportunities for itself. Noble’s directors and officers have a fiduciary duty to make these decisions in the best interests of the stockholders of Noble;

• Noble may be constrained by the terms of its debt instruments from taking actions, or refraining from taking actions, that may be in our best interests;

• our partnership agreement replaces the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing its duties and limits our general partner’s liabilities and the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty under applicable Delaware law;

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

• our general partner will determine the amount and timing of, among other things, cash expenditures, borrowings and repayments of indebtedness, the issuance of additional partnership interests, the creation, increase or reduction in cash reserves in any quarter and asset purchases and sales, each of which can affect the amount of cash that is available for distribution to unitholders;

• our general partner will determine the amount and timing of any capital expenditures and whether a capital expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus. This determination can affect the amount of cash that is distributed to our unitholders and to our general partner, the amount of adjusted operating surplus generated in any given period and the ability of the subordinated units to convert into common units;

• our general partner will determine which costs incurred by it are reimbursable by us;

• our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make a distribution on the subordinated units, to make incentive distributions or to accelerate expiration of the subordination period;

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

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

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

• our general partner may exercise its right to call and purchase all of the common units not owned by it and its affiliates if it and its affiliates own more than 80% of the common units;

• our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates, including our gathering agreements with Noble;

• our general partner decides whether to retain separate counsel, accountants or others to perform services for us; and

• Noble, or any transferee holding incentive distribution rights, may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to its incentive distribution rights, without the approval of the conflicts committee of the board of directors of our general partner, which we refer to as our conflicts committee, or our common unitholders. This election could result in lower distributions to our common unitholders in certain situations.

Neither our partnership agreement nor our omnibus agreement will prohibit Noble 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 Noble 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. 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, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. Consequently, Noble 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 Noble and other affiliates of our general partner could materially and adversely impact our results of operations and distributable cash flow. This may create actual and potential conflicts of interest between us and affiliates of our general partner and result in less than favorable treatment of us and our unitholders. Please read “Certain Relationships and Related Party Transactions—Agreements with our Affiliates in Connection with the Transactions—Omnibus Agreement” and “Conflicts of Interest and Duties.”

Our partnership agreement requires that we distribute all of our available cash, which could limit our ability to grow and make acquisitions.

Our partnership agreement requires that we distribute all of our available cash to our unitholders. As a result, we expect to rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. Therefore, to the extent we are unable to finance our growth externally, our cash distribution policy will significantly impair our ability to grow. In addition, because we will distribute all of our available cash, our growth may not be as fast as that of businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional partnership interests in connection with any acquisitions or expansion capital expenditures, the

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payment of distributions on those additional partnership interests 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 partnership interests, including partnership interests ranking senior to our common units as to distributions or in liquidation or that have special voting rights and other rights, and our common unitholders will have no preemptive or other rights (solely as a result of their status as common unitholders) to purchase any such additional partnership interests. The incurrence of additional commercial bank borrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn, may reduce the amount of cash that we have available to distribute to our unitholders.

Our general partner will be required to deduct estimated maintenance capital expenditures from our operating surplus, which may result in less cash available for distribution to unitholders from operating surplus than if actual maintenance capital expenditures were deducted.

Maintenance capital expenditures are those capital expenditures made to maintain, over the long term, our operating capacity or operating income. Our partnership agreement requires our general partner to deduct estimated, rather than actual, maintenance capital expenditures from operating surplus in determining cash available for distribution from operating surplus. The amount of estimated maintenance capital expenditures deducted from operating surplus will be subject to review and change by our general partner’s board of directors at least once a year, provided that any change is approved by the conflicts committee of our general partner’s board of directors. Our partnership agreement does not cap the amount of maintenance capital expenditures that our general partner may estimate. In years when our estimated maintenance capital expenditures are higher than actual maintenance capital expenditures, the amount of cash available for distribution to unitholders from operating surplus will be lower than if actual maintenance capital expenditures had been deducted from operating surplus. On the other hand, if our general partner underestimates the appropriate level of estimated maintenance capital expenditures, we will have more cash available for distribution from operating surplus in the short term but will have less cash available for distribution from operating surplus in future periods when we have to increase our estimated maintenance capital expenditures to account for the previous underestimation.

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

Delaware law provides that a Delaware limited partnership may, in its partnership agreement, expand, restrict or eliminate the fiduciary duties otherwise owed by the general partner to limited partners and the partnership, provided that the partnership agreement may not eliminate the implied contractual covenant of good faith and fair dealing. This implied covenant is a judicial doctrine utilized by Delaware courts in connection with interpreting ambiguities in partnership agreements and other contracts, and does not form the basis of any separate or independent fiduciary duty in addition to the express contractual duties set forth in our partnership agreement. Under the implied contractual covenant of good faith and fair dealing, a court will enforce the reasonable expectations of the partners where the language in the partnership agreement does not provide for a clear course of action.

As permitted by Delaware law, our partnership agreement contains provisions that eliminate the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty law and replaces those duties with several different contractual standards. 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, free of any duties to us and our unitholders. This provision entitles our general partner to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our limited partners. By purchasing a common unit, a unitholder is treated as having consented to the provisions in our partnership agreement, including the provisions discussed above. Please read “Conflicts of Interest and Duties—Duties of Our General Partner.”

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

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

• provides that whenever our general partner makes a determination or takes, or declines to take, any other action in its capacity as our general partner, our general partner is required to make such determination, or take or decline to take such other action, in good faith, meaning that it subjectively believed that the determination or the decision to take or decline to take such action was in the best interests of our partnership, and will not be subject to any other or different standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity;

• provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as it acted in good faith;

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

• provides that our general partner will not be in breach of its obligations under our partnership agreement or its fiduciary duties to us or our limited partners if a transaction with an affiliate or the resolution of a conflict of interest is approved in accordance with, or otherwise meets the standards set forth in, our partnership agreement.

In connection with a situation involving a transaction with an affiliate or a conflict of interest, our partnership agreement provides that any determination by our general partner must be made in good faith, and that our conflicts committee and the board of directors of our general partner are entitled to a presumption that they acted in good faith. 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. Please read “Conflicts of Interest and Duties.”

Cost reimbursements, which will be determined in our general partner’s sole discretion, and fees due our general partner and its affiliates for services provided will be substantial and will reduce the amount of cash we have available for distribution to you.

Under our partnership agreement, we are required to reimburse our general partner and its affiliates for all costs and expenses that they incur on our behalf for managing and controlling our business and operations. Except to the extent specified under our omnibus agreement and operational services agreement, our general partner determines the amount of these expenses. Under the terms of the omnibus agreement, we will be required to reimburse Noble for the provision of certain administrative support services to us. Under our operational services agreement, we will be required to reimburse Noble for the provision of certain maintenance, operating, administrative and construction services in support of our operations. Our general partner and its affiliates also may provide us other services for which we will be charged fees as determined by our general partner. The costs and expenses for which we will reimburse our general partner and its affiliates may 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. The costs and expenses for which we are required to reimburse our general partner and its affiliates are not subject to any caps or other limits. We estimate that the total amount of such reimbursed expenses will be approximately $         million for the twelve months ending September 30, 2016. Please read “Cash Distribution Policy and Restrictions on Distributions—Estimated

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EBITDA and Distributable Cash Flow for the Twelve Months Ending September 30, 2016.” Payments to our general partner and its affiliates will be substantial and will reduce the amount of cash we have available to distribute to unitholders.

Unitholders have very limited voting rights and, even if they are dissatisfied, they will have limited ability to remove our general partner.

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. For example, unlike holders of stock in a public corporation, unitholders will not have “say-on-pay” advisory voting rights. Unitholders did not elect our general partner or the board of directors of our general partner and will have no right to elect our general partner or the board of directors of our general partner on an annual or other continuing basis. The board of directors of our general partner is chosen by its sole member, which is owned by Noble. Furthermore, if the unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. 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.

Our general partner may not be removed unless such removal is both (i) for cause and (ii) approved by a vote of the holders of at least 66 ²/₃% of the outstanding units, including any units owned by our general partner and its affiliates, voting together as a single class. “Cause” is narrowly defined under our partnership agreement to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding our general partner liable to us or any limited partner for actual fraud or willful misconduct in its capacity as our general partner. Cause does not include most cases of charges of poor management of the business. Following the completion of this offering, Noble will own     % of our total outstanding common units and subordinated units on an aggregate basis (or     % of our total outstanding common units and subordinated units on an aggregate basis if the underwriters exercise in full their option to purchase additional common units). As a result, our public unitholders will have limited ability to remove our general partner.

Furthermore, unitholders’ voting rights are further restricted by the partnership agreement provision providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates, 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.

Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.

Our general partner interest or the control of our general partner may be transferred to a third party without unitholder consent.

Our general partner may transfer its general partner interest in us to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, there is no restriction in our partnership agreement on the ability of Noble to transfer its membership interest in our general partner to a third party. The new owner of our general partner would then be in a position to replace the board of directors and officers of our general partner with its own choices.

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

Noble may transfer our incentive distribution rights to a third party at any time without the consent of our unitholders. If Noble transfers our incentive distribution rights to a third party but retains its ownership of our

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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 Noble could reduce the likelihood of Noble selling or contributing additional midstream assets to us, as Noble would have less of an economic incentive to grow our business, which in turn would impact our ability to grow our asset base.

We may issue an unlimited number of additional partnership interests without unitholder approval, which would dilute unitholder interests.

At any time, we may issue an unlimited number of general partner interests or limited partner interests of any type without the approval of our unitholders and our unitholders will have no preemptive or other rights (solely as a result of their status as unitholders) to purchase any such general partner interests or limited partner interests. Further, there are no limitations in our partnership agreement on our ability to issue equity securities that rank equal or senior to our common units as to distributions or in liquidation or that have special voting rights and other rights. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:

• our unitholders’ proportionate ownership interest in us will decrease;

• the amount of cash we have available to distribute on each unit may decrease;

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

• the ratio of taxable income to distributions may increase;

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

• the market price of our common units may decline.

The issuance by us of additional general partner interests may have the following effects, among others, if such general partner interests are issued to a person who is not an affiliate of Noble:

• management of our business may no longer reside solely with our current general partner; and

• affiliates of the newly admitted general partner may compete with us, and neither that general partner nor such affiliates will have any obligation to present business opportunities to us except with respect to rights of first refusal contained in our omnibus agreement.

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

After the completion of this offering, assuming that the underwriters do not exercise their option to purchase additional common units, Noble will hold              common units and              subordinated units. All of the subordinated units will convert into common units at the end of the subordination period and may convert earlier under certain circumstances. Additionally, we have agreed to provide Noble with certain registration rights under applicable securities laws. Please read “Units Eligible for Future Sale.” The sale of these units in the public or private markets could have an adverse impact on the price of the common units or on any trading market that may develop.

Our general partner’s discretion in establishing cash reserves may reduce the amount of cash we have available 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

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permits the general partner to reduce available 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 cash we have available to distribute to unitholders.

Affiliates of our general partner, including Noble, 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 dedications contained in our commercial agreements and rights of first refusal contained in our omnibus agreement.

None of our partnership agreement, our omnibus agreement, our commercial agreements or any other agreement in effect as of the date of this offering will prohibit Noble 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 Noble 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. 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, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. Consequently, Noble 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 Noble and other affiliates of our general partner could materially and adversely impact our results of operations and distributable cash flow.

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

If at any time our general partner and its affiliates own more than 80% of our then-outstanding common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then current market price. As a result, you may be required to sell your common units at an undesirable time or price and may not receive any return on your investment. You may also incur a tax liability upon a sale of your units. Following the completion of this offering and assuming the underwriters’ option to purchase additional common units from us is not exercised, our general partner and its affiliates will own approximately     % of our common units (excluding any common units purchased by the directors, director nominee and executive officers of our general partner and certain other individuals as selected by our general partner under our directed unit program). At the end of the subordination period (which could occur as early as within the quarter ending September 30, 2016), assuming no additional issuances of common units by us (other than upon the conversion of the subordinated units) and the underwriters’ option to purchase additional common units from us is not exercised, our general partner and its affiliates will own approximately     % of our outstanding common units (excluding any common units purchased by the directors, director nominee and executive officers of our general partner and certain other individuals as selected by our general partner under our directed unit program) and therefore would not be able to exercise the call right at that time. Please read “Our Partnership Agreement—Limited Call Right.”

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

Under certain circumstances, unitholders may have to repay amounts wrongfully distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, or the Delaware Act, we may not make a distribution to you 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

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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. Transferees of common units are liable for the obligations of the transferor to make contributions to the partnership that are known to the transferee at the time of the transfer and for unknown obligations if the liabilities could be determined from our partnership agreement. 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 you with adequate liquidity may not develop. The price of our common units may fluctuate significantly, and you could lose all or part of your investment.

Prior to this offering, there has been no public market for our common units. After this offering, there will be only publicly traded common units, assuming the underwriters’ option to purchase additional common units from us is not exercised. In addition, following the completion of this offering, Noble will own              common units and subordinated units, representing an aggregate     % limited partner interest (or              common units and subordinated units, representing an aggregate     % limited partner interest, if the underwriters exercise in full their option to purchase additional common units). We do not know the extent to which investor interest will lead to the development of an active trading market or how liquid that market might be. You may not be able to resell your common units at or above the initial public offering price. Additionally, the 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 offered hereby 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.

Noble, or any transferee holding incentive distribution rights, may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to its incentive distribution rights, without the approval of our conflicts committee or our common unitholders. This election could result in lower distributions to our common unitholders in certain situations.

Noble, as the initial holder of our incentive distribution rights, has the right, at any time when there are no subordinated units outstanding and it has received distributions on its incentive distribution rights at the highest level to which it is entitled (50%) for each of 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 Noble 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 Noble will be equal to that number of common units that would have entitled their holder to an average aggregate quarterly cash distribution in the prior two quarters equal to the average of the distributions on the incentive distribution rights in such two quarters. We anticipate that Noble 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 Noble 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 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

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that they would have otherwise received had we not issued new common units in connection with resetting the target distribution levels. Additionally, Noble has the right to transfer all or any portion of our incentive distribution rights at any time, and such transferee will have the same rights as Noble relative to resetting target distributions if our general partner concurs that the tests for resetting target distributions have been fulfilled. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions—Noble’s Right to Reset Incentive Distribution Levels.”

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 limited partners 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 the Federal Energy Regulatory Commission or similar regulatory body and (ii) nationality, citizenship or other related status does not create and is not reasonably likely to 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 limited partner interests of the class to be so redeemed multiplied by the number of limited partner interests of each such class included among the redeemable interests. For these purposes, the “current market price” means, as of any date for any class of limited partner interests, the average of the daily closing prices per limited partner interest of such class 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 “Our Partnership Agreement—Possible Redemption of Ineligible Holders.”

Our partnership agreement will designate the Court of Chancery of the State of Delaware as the exclusive forum for certain types of actions and proceedings that may be initiated by our unitholders, which would limit our unitholders’ ability to choose the judicial forum for disputes with us or our general partner’s directors, officers or other employees. 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 action.

Our partnership agreement will provide that, with certain limited exceptions, 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) shall be the exclusive forum for any claims, suits, actions or proceedings (i) arising out of or relating in any way to our partnership agreement (including any claims, suits or actions to interpret, apply or enforce the provisions of our partnership agreement or the duties, obligations or liabilities among our partners, or obligations or liabilities of our partners to us, or the rights or powers of, or restrictions on, our partners or us), (ii) brought in a derivative manner on our behalf, (iii) asserting a claim of breach of a duty owed by any of our, or our general partner’s, directors, officers, or other employees, or owed by our general partner, to us or our partners, (iv) asserting a claim against us arising pursuant to any provision of the Delaware Act or (v) asserting a claim against us governed by the internal affairs doctrine.

If any person 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

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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. In addition, our partnership agreement provides that each limited partner irrevocably waives the right to trial by jury in any such claim, suit, action or proceeding. 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. These provisions may have the effect of discouraging lawsuits against us and our general partner’s directors and officers. Please read “Our Partnership Agreement—Applicable Law; Exclusive Forum.”

The NYSE does not require a publicly traded limited 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 limited 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. Additionally, any future issuance of additional common units or other securities, including to affiliates, will not be subject to the NYSE’s shareholder approval rules that apply to a corporation. Accordingly, unitholders will not have the same protections afforded to certain corporations that are subject to all of the NYSE corporate governance requirements. Please read “Management—Management of Noble Midstream Partners LP.”

If we fail to establish and maintain effective internal control over financial reporting, our ability to accurately report our financial results could be adversely affected.

We are not currently required to comply with the SEC’s rules implementing Section 404 of the Sarbanes- Oxley Act of 2002, and are therefore not required to make a formal assessment of the effectiveness of our internal control over financial reporting for that purpose. Upon becoming a publicly traded partnership, we will be required to comply with the SEC’s rules implementing Sections 302 and 404 of the Sarbanes-Oxley Act of 2002, which will require our management to certify financial and other information in our quarterly and annual reports and provide an annual management report on the effectiveness of our internal control over financial reporting. Though we will be required to disclose material changes made to our internal controls and procedures on a quarterly basis, we will not be required to make our first annual assessment of our internal control over financial reporting pursuant to Section 404 until the year following our first annual report required to be filed with the SEC. To comply with the requirements of being a publicly traded partnership, we may need to implement additional internal controls, reporting systems and procedures and hire additional accounting, finance and legal staff. Furthermore, while we generally must comply with Section 404 of the Sarbanes-Oxley Act of 2002 for our fiscal year ending December 31, 2015, we are not required to have our independent registered public accounting firm attest to the effectiveness of our internal controls until our first annual report subsequent to our ceasing to be an “emerging growth company” within the meaning of Section 2(a)(19) of the Securities Act. Accordingly, we may not be required to have our independent registered public accounting firm attest to the effectiveness of our internal controls until our annual report for the fiscal year ending December 31, 2019. Once it is required to do so, our independent registered public accounting firm may issue a report that is adverse in the event it is not satisfied with the level at which our controls are documented, designed, operated or reviewed.

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

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processes and reporting in the future or that we will be able to comply with our obligations under Section 404 of 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 management’s assessment of 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 $1.0 billion of revenues in a fiscal year, become a large accelerated filer or issue more than $1.0 billion of non-convertible debt 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.

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 cash we have available for distribution to our unitholders 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.

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 $         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.

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If we are deemed 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 operating subsidiaries as well as ownership interests in other midstream ventures. If a sufficient amount of our assets, such as such ownership interests or other assets acquired in the future, 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. In that event, it is possible that our ownership of these interests, combined with our assets acquired in the future, could result in our being required to register under the Investment Company Act if we were not successful in obtaining exemptive relief or otherwise modifying our organizational structure or applicable contract rights. 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 distributions 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 cash available for distribution to you 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 the unitholders, likely causing a substantial reduction in the value of our common units. Please read “Material Federal Income Tax Consequences—Partnership Status.”

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 midstream systems from Noble, restrict our ability to borrow funds or engage in other transactions involving leverage and require us to add additional directors who are independent of us or our affiliates. The occurrence of some or all of these events would adversely affect the price of our common units and could have a material adverse effect on our business.

Tax Risks

In addition to reading the following risk factors, please read “Material 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. If the IRS were to treat us as a corporation for federal income tax purposes, which would subject us to entity-level taxation, or if we were otherwise subjected to a material amount of entity-level taxation, then our distributable cash flow to our unitholders would be substantially reduced.

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

Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. Based upon our current operations, we believe we satisfy the qualifying income requirement. Although we have requested a ruling from the IRS as to whether income derived from our water-related activities constitutes qualifying income, this offering is not contingent upon receipt of a favorable ruling pursuant to that request and no ruling has been requested from the IRS regarding our characterization as a partnership for 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 federal income tax purposes or otherwise subject us to taxation as an entity.

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%, and would likely pay state and local income tax at varying rates. Distributions would generally be taxed again as corporate dividends (to the

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extent of our current and accumulated earnings and profits), and no income, gains, losses, deductions, or credits would flow through to you. Because a tax would be imposed upon us as a corporation, our distributable cash flow would be substantially reduced. In addition, changes in current state law may subject us to entity-level taxation by individual states. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of any such taxes may substantially reduce the cash available for distribution to you. Therefore, if we were treated as a corporation for federal income tax purposes or otherwise subjected to a material amount of entity-level taxation, there would be 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.

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 levels may be adjusted to reflect the impact of that law on us.

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

The present 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 interpretation at any time. For example, from time to time, the President and members of Congress propose and consider substantive changes to the existing federal income tax laws that affect publicly traded partnerships, including elimination of partnership tax treatment for publicly traded partnerships. Any modification to the federal income tax laws and interpretations thereof may or may not be retroactively applied and could make it more difficult or impossible for us to meet the exception to be treated as a partnership for federal income tax purposes. Please read “Material Federal Income Tax Consequences—Partnership Status.”

On May 5, 2015, the U.S. Treasury Department and the IRS released proposed regulations, or the Proposed Regulations, regarding qualifying income under Section 7704(d)(1)(E) of the Code. The U.S. Treasury Department and the IRS have requested comments from industry participants regarding the standards set forth in the Proposed Regulations. The Proposed Regulations provide an exclusive list of industry-specific activities and certain limited support activities that generate qualifying income, including water-related activities when provided for use in drilling and hydraulic fracturing activities.

Although the Proposed Regulations adopt a narrow interpretation of the water-related activities that generate qualifying income, we believe the income that we treat as qualifying satisfies these requirements and our counsel will rely on the Proposed Regulations to treat income from certain of our water-related activities as qualifying income and to meet the exception for us to be treated as a partnership for federal income tax purposes.

However, the Proposed Regulations could be changed before they are finalized and could take a position that is contrary to our interpretation. In the event that we do not satisfy the standards set forth in the final regulations for the water-related services or other income that we treat as qualifying, we anticipate being able to continue to treat income from these activities as qualifying income for ten years under special transition rules provided in the Proposed Regulations.

We are unable to predict whether any of these changes, or other proposals, will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units. 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 income tax purposes, the minimum quarterly distribution and the target distribution levels may be adjusted to reflect the impact of that law on us.

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Our unitholders’ share of our income will be taxable to them for federal income tax purposes even if they do not receive any cash distributions from us.

Because a unitholder will be treated as a partner to whom we will allocate taxable income that could be different in amount than the cash we distribute, a unitholder’s allocable share of our taxable income will be taxable to it, which may require the payment of federal income taxes and, in some cases, state and local income taxes, on its share of our taxable income even if it receives no cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income.

If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS contest will reduce our distributable cash flow to our unitholders.

We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the conclusions of our counsel expressed in this prospectus or from the positions we take, and the IRS’s positions may ultimately be sustained. 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 and such positions may not ultimately be sustained. A court may not agree with some or all of our counsel’s conclusions or the positions we take. Any contest with the IRS, and the outcome of any IRS contest, may have a materially adverse impact on the market for our common units and the price at which they 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 flow.

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

If our unitholders sell common units, they will recognize a gain or loss for federal income tax purposes equal to the difference between the amount realized and their tax basis in those common units. Because distributions in excess of their allocable share of our net taxable income decrease their tax basis in their 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 the unitholder if it sells such common units at a price greater than its tax basis in those common units, even if the price received is less than its original cost. Furthermore, a substantial portion of the amount realized on any sale of your common units, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, a unitholder that sells common units may incur a tax liability in excess of the amount of cash received from the sale. Please read “Material Federal Income Tax Consequences—Disposition of Common Units—Recognition of Gain or Loss.”

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 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 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 reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file federal income tax returns and pay tax on their share of our taxable income. If you are a tax-exempt entity or a non-U.S. person, you should consult a tax advisor before investing in our common units.

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

Because we cannot match transferors and transferees of common units and because of other reasons, we will adopt depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to you. Andrews Kurth LLP is unable to opine as to the validity of such filing positions. It also could affect the timing of these tax benefits or the amount of gain from your sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to your tax returns. Please read “Material Federal Income Tax Consequences—Tax Consequences of Unit Ownership—Section 754 Election.”

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

We will prorate our items of income, gain, loss and deduction for federal income tax purposes between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations, and, accordingly, our counsel is unable to opine as to the validity of this method. The U.S. Treasury Department and the IRS have issued proposed regulations that provide a safe harbor pursuant to which publicly traded partnerships may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we will adopt. If the IRS were to challenge this method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders. Andrews Kurth LLP has not rendered an opinion with respect to whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations. Please read “Material Federal Income Tax Consequences—Disposition of Common Units—Allocations Between Transferors and Transferees.”

A unitholder whose common units are loaned to a “short seller” to effect a short sale of common units may be considered as having disposed of those common units. If so, he would no longer be treated for federal income 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 a unitholder whose common units are loaned to a “short seller” to effect a short sale of common units may be considered as having disposed of the loaned common units, he may no longer be treated for federal income 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 to the short seller, 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. Andrews Kurth LLP has not rendered an opinion regarding the treatment of a unitholder where common units are loaned to a short seller to effect a short sale of common units; therefore, our unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to consult a tax advisor to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from loaning their common units.

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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, and such a challenge could adversely affect the value of our common units.

In determining the items of income, gain, loss and deduction allocable to our unitholders, in certain circumstances, including when we issue additional units, we must determine the fair market value of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we make many fair market value estimates ourselves using a methodology based on the market value of our common units as a means to determine the fair market value of our assets. The IRS may challenge these valuation methods and the resulting allocations of income, gain, loss and deduction for federal income tax purposes.

A successful IRS challenge to these methods or allocations could adversely affect the amount, character and timing of taxable income or loss allocated to our unitholders. It also could affect the amount of gain from our unitholders’ sale of common units and could 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 federal income tax purposes.

We will be considered to have technically 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. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest will be counted only once. Our technical 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 (and our unitholders could receive two Schedules K-1 if relief was not available, as described below) for one fiscal year and could result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead we would be treated as a new partnership for federal income tax purposes. If treated as a new partnership, we must make new tax elections, including a new election under Section 754 of the Internal Revenue Code and could be subject to penalties if we are unable to determine that a termination occurred. The IRS has announced a publicly traded partnership technical termination relief program whereby, if a publicly traded partnership that technically terminated requests publicly traded partnership technical termination relief and such relief is granted by the IRS, among other things, the partnership will only have to provide one Schedule K-1 to unitholders for the year notwithstanding two partnership tax years. Please read “Material Federal Income Tax Consequences—Disposition of Common Units—Constructive Termination.”

As a result of investing in our common units, you may become subject to state and local taxes and return filing requirements in jurisdictions where we operate or own or acquire properties.

In addition to federal income taxes, our unitholders will likely be subject to other taxes, including 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 control 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 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. As we make acquisitions or expand our business, we may control assets or conduct business in additional states that impose a personal income tax. It is your responsibility to file all federal, state and local tax returns. Our counsel has not rendered an opinion on the state or local tax consequences of an investment in our common units. Please consult your tax advisor.

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USE OF PROCEEDS

We expect to receive net proceeds of approximately $         million from the sale of             common units offered by this prospectus, based on an assumed initial public offering price of $         per common unit (the mid-point of the price range set forth on the cover page of this prospectus), after deducting underwriting discounts and commissions, the structuring fee 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 to (i) make a distribution of approximately $         million to Noble and (ii) pay approximately $         million of origination fees related to our new revolving credit facility.

If and to the extent the underwriters exercise their option to purchase additional common units, the number of common units purchased by the underwriters pursuant to such exercise will be issued to the public and the remainder of the             additional common units, if any, will be issued to Noble at the expiration of the option period. Any such common units issued to Noble will be issued for no additional consideration. If the underwriters exercise in full their option to purchase additional common units, we expect to receive net proceeds of approximately $         million, after deducting underwriting discounts and commissions, the structuring fee and estimated offering expenses. We will use any net proceeds from the exercise of the underwriters’ option to purchase additional common units to make a cash distribution to Noble.

Depending on market conditions at the time of pricing of this offering and other considerations, we may sell fewer or more common units than the number set forth on the cover page of this prospectus.

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CAPITALIZATION

The following table sets forth:

• the historical cash and cash equivalents and capitalization of our Predecessor as of March 31, 2015; and

• our pro forma capitalization as of March 31, 2015, giving effect to the pro forma adjustments described in our unaudited pro forma combined financial statements included elsewhere in this prospectus, including this offering and the application of the net proceeds from this offering in the manner described under “Use of Proceeds” and the other transactions described under “Prospectus Summary—The Transactions.”

The following table assumes that the underwriters do not exercise their option to purchase additional common units. If and to the extent the underwriters exercise their option to purchase additional common units, the number of common units purchased by the underwriters pursuant to such exercise will be issued to the public and the remainder of the             additional common units, if any, will be issued to Noble at the expiration of the option period. Any such common units will be issued for no additional consideration.

This table is derived from, should be read together with and is qualified in its entirety by reference to the historical financial statements and the accompanying notes and the unaudited pro forma combined financial statements and the accompanying notes included elsewhere in this prospectus. You should also read this table in conjunction with “Prospectus Summary—The Transactions,” “Use of Proceeds,” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

	As of March 31, 2015
	Historical		Pro Forma
	(in thousands)
Cash and cash equivalents	$	9,930	$
Long-term debt:
Revolving credit facility(1)	$	—	$	—
Total long-term debt (including current maturities)		—		—
Net parent investment / partners’ capital:
Net parent investment		235,812		—
Held by public:
Common units		—
Held by Noble:
Common units		—
Subordinated units		—
General partner interest(2)		—		—
Total equity		235,812
Non-controlling interest		—
Total partners’ capital		235,812
Total capitalization	$	235,812	$

(1) In connection with the completion of this offering, we expect to enter into a new $         million revolving credit facility. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Capital Resources and Liquidity—Revolving Credit Facility.”

(2) Upon completion of this offering, our general partner will own a non-economic general partner interest in us.

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DILUTION

Dilution is the amount by which the offering price per common unit in this offering will exceed the pro forma net tangible book value per common unit after the offering. On a pro forma basis as of March 31, 2015, after giving effect to the offering of common units and the related transactions, our net tangible book value was approximately $         million, or $         per common unit. Purchasers of common units in this offering will experience substantial and immediate dilution in pro forma net tangible book value per common unit for financial accounting purposes, as illustrated in the following table.

Assumed initial public offering price per common unit(1)		$
Pro forma net tangible book value per unit before this offering(2)	$
Less: Distribution to Noble(3)
Add: Increase in net tangible book value per unit attributable to purchasers in this offering
Less: Pro forma net tangible book value per unit after this offering(4)
Immediate dilution in net tangible book value per common unit to purchasers in this offering(5)(6)		$

(1) Represents the mid-point of the price range set forth on the cover page of this prospectus.

(2) Determined by dividing the number of units (             common units and             subordinated units) to be issued to the general partner and its affiliates for their contribution of assets and liabilities to us into the pro forma net tangible book value of the contributed assets and liabilities of $         million.

(3) Determined by dividing the number of units (             common units and              subordinated units) to be issued to Noble for its contribution of assets and liabilities to us. At the closing of this offering, we intend to make a distribution of $         million to Noble.

(4) Determined by dividing the number of units to be outstanding after this offering (             common units and                 subordinated units) and the application of the related net proceeds into our pro forma net tangible book value, after giving effect to the application of the net proceeds from this offering, of $         million.

(5) If the initial public offering price were to increase or decrease by $1.00 per common unit, then dilution in net tangible book value per common unit would equal $         and $        , respectively.

(6) Because the total number of units outstanding following this offering will not be impacted by any exercise of the underwriters’ option to purchase additional common units and any net proceeds from such exercise will not be retained by us, there will be no change to the dilution in net tangible book value per common unit to purchasers in this offering due to any such exercise of the option.

The following table sets forth the partnership interests that we will issue and the total consideration contributed to us by our general partner and its affiliates in respect of their partnership interests and by the purchasers of common units in this offering upon consummation of the transactions contemplated by this prospectus.

	Units Acquired			Total Consideration
	Number	%		Amount (in millions)	%
Noble and its affiliates(1)(2)(3)			%	$		%
Purchasers in this offering			%			%
Total			%	$		%

(1) Upon the completion of this offering, Noble and will own             common units and              subordinated units.

(2) Assumes the underwriters’ option to purchase additional common units is not exercised.

(3) The assets contributed by Noble were recorded at historical cost in accordance with accounting principles generally accepted in the United States. Book value of the consideration provided by our general partner and its affiliates, as of March 31, 2015 was $         million. At the closing of this offering, we intend to make a distribution of $         million to Noble.

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CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

The following discussion of our cash distribution policy should be read in conjunction with the specific assumptions included in this section. In addition, you should read “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 and pro forma results of operations, please refer to our historical financial statements and the accompanying notes and the unaudited pro forma condensed financial statements and the accompanying notes included elsewhere in this prospectus.

General

Rationale for Our Cash Distribution Policy

Our partnership agreement requires that we distribute all of our available cash quarterly. This requirement forms the basis of our cash distribution policy and reflects a basic judgment that our unitholders will be better served by distributing our available cash rather than retaining it because, among other reasons, we believe we will generally finance any expansion capital expenditures from external financing sources. Under our current cash distribution policy, we intend to make a minimum quarterly distribution to the holders of our common units and subordinated units of $         per unit, or $         per unit on an annualized basis, to the extent we have sufficient available cash after the establishment of cash reserves (including estimated maintenance capital expenditures) and the payment of costs and expenses, including the payment of expenses to our general partner. However, other than the requirement in our partnership agreement to distribute all of our available cash each quarter, we have no legal obligation to make quarterly cash distributions in this or any other amount, and the board of directors of our general partner has considerable discretion to determine the amount of our available cash each quarter. In addition, the board of directors of our general partner may change our cash distribution policy at any time, subject to the requirement in our partnership agreement to distribute all of our available cash quarterly. Generally, our available cash is the sum of (i) all cash on hand at the end of a quarter after the payment of our expenses and the establishment of cash reserves and (ii) if the board of directors of our general partner so determines, all or any portion of additional cash on hand resulting from working capital borrowings made after the end of the quarter. Because we are not subject to an entity-level federal income tax, we expect to have more cash to distribute than would be the case if we were subject to federal income tax. If we do not generate sufficient available cash from our operations, we may, but are under no obligation to, borrow funds to pay the minimum quarterly distribution to our unitholders.

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

Although our partnership agreement requires that we distribute all of our available cash quarterly, there is no guarantee that we will make quarterly cash distributions to our unitholders at our minimum quarterly distribution rate or at any other rate, and we have no legal obligation to do so. Our current cash distribution policy is subject to certain restrictions, as well as the considerable discretion of the board of directors of our general partner in determining the amount of our available cash each quarter. The following factors will affect our ability to make cash distributions, as well as the amount of any cash distributions we make:

• We expect that our cash distribution policy will be subject to restrictions on cash distributions under our new revolving credit facility. We expect that one such restriction would prohibit us from making cash distributions while an event of default has occurred and is continuing under our new revolving credit facility, notwithstanding our cash distribution policy. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Capital Resources and Liquidity—Revolving Credit Facility.”

• The amount of cash that we distribute and the decision to make any distribution is determined by the board of directors of our general partner, taking into consideration the terms of our partnership agreement. Specifically, the board of directors of our general partner will have the authority to establish

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cash reserves to provide for the proper conduct of our business, comply with applicable law or any agreement to which we are a party or by which we are bound or our assets are subject and provide funds for future cash distributions to our unitholders, and the establishment of or increase in those reserves could result in a reduction in cash distributions from levels we currently anticipate pursuant to our stated cash distribution policy. Any decision to establish cash reserves made by the board of directors of our general partner in good faith will be binding on our unitholders.

• While our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including the provisions requiring us to make cash distributions, may be amended. During the subordination period, our partnership agreement may not be amended without the approval of our public common unitholders, except in a limited number of circumstances when our general partner can amend our partnership agreement without any unitholder approval. Please read “Our Partnership Agreement—Amendment of Our Partnership Agreement—No Unitholder Approval.” However, after the subordination period has ended, our partnership agreement may be amended with the consent of our general partner and the approval of a majority of the outstanding common units, including common units owned by our general partner and its affiliates. Following the completion of this offering, Noble will own our general partner,             common units and             subordinated units, representing an aggregate     % limited partner interest (or common units and subordinated units, representing an aggregate     % limited partner interest, if the underwriters exercise in full their option to purchase additional common units).

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

• We may lack sufficient cash to pay distributions to our unitholders due to cash flow shortfalls attributable to a number of operational, commercial or other factors as well as increases in our operating or general and administrative expenses, principal and interest payments on our debt, tax expenses, working capital requirements and anticipated cash needs. Our available cash is directly impacted by the cash expenses necessary to run our business and will be reduced dollar-for-dollar to the extent such uses of cash increase. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions—Distributions of Available Cash.”

• Our ability to make cash distributions to our unitholders depends on the performance of our operating subsidiaries and their ability to distribute cash to us.

• If and to the extent our available cash materially declines from quarter to quarter, we may elect to change our current cash distribution policy and reduce the amount of our quarterly distributions in order to service or repay our debt or fund expansion capital expenditures.

To the extent that our general partner determines not to distribute the full minimum quarterly distribution on our common units with respect to any quarter during the subordination period, the common units will accrue an arrearage equal to the difference between the minimum quarterly distribution and the amount of the distribution actually paid on the common units with respect to that quarter. The aggregate amount of any such arrearages must be paid on the common units before any distributions of available cash from operating surplus may be made on the subordinated units and before any subordinated units may convert into common units. The subordinated units will not accrue any arrearages. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions—Subordinated Units and Subordination Period.”

Our Ability to Grow Is Dependent on Our Ability to Access External Expansion Capital

Our partnership agreement requires us to distribute all of our available cash to our unitholders on a quarterly basis. As a result, we expect that we will rely primarily upon our cash reserves and external financing sources, including borrowings under our new revolving credit facility and the issuance of debt and equity securities, to fund future acquisitions and other expansion capital expenditures. While we have historically received funding from Noble, we do not have any commitment from Noble, our general partner or any of their respective affiliates

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to fund our cash flow deficits or provide other direct or indirect financial assistance to us following the closing of this offering. Following the completion of this offering, Noble will directly own a     % limited partner interest in us (or a     % limited partner interest in us if the underwriters exercise in full their option to purchase additional common units). In addition, Noble will wholly own our general partner and all of our incentive distribution rights. Given Noble’s significant ownership interests in us following the closing of this offering, we believe Noble will be incentivized to promote and support the successful execution of our business strategies, including by providing us with direct or indirect financial assistance; however, we can provide no assurances that Noble will provide such direct or indirect financial assistance.

To the extent we are unable to finance growth with external sources of capital, the requirement in our partnership agreement to distribute all of our available cash and our current cash distribution policy may significantly impair our ability to grow. In addition, because we will distribute all of our available cash, our growth may not be as fast as businesses that reinvest all of their available cash to expand ongoing operations. We expect that our new revolving credit facility will restrict our ability to incur additional debt, including through the issuance of debt securities. Please read “Risk Factors—Risks Related to Our Business—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.” To the extent we issue additional partnership interests, the payment of distributions on those additional partnership interests may increase the risk that we will be unable to maintain or increase our cash distributions per common unit. There are no limitations in our partnership agreement on our ability to issue additional partnership interests, including partnership interests ranking senior to our common units, and our common unitholders will have no preemptive or other rights (solely as a result of their status as unitholders) to purchase any such additional partnership interests. If we incur additional debt (under our new revolving credit facility or otherwise) to finance our growth strategy, we will have increased interest expense, which in turn will reduce the available cash that we have to distribute to our unitholders. Please read “Risk Factors—Risks Related to Our Business—Debt we incur in the future may limit our flexibility to obtain financing and to pursue other business opportunities.”

Our Minimum Quarterly Distribution

Upon the consummation of this offering, our partnership agreement will provide for a minimum quarterly distribution of $         per unit for each whole quarter, or $         per unit on an annualized basis. 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.” Quarterly distributions, if any, will be made within 45 days after the end of each calendar quarter to holders of record on or about the first day of each such month in which such distributions are made. We do not expect to make distributions for the period that began on                     and ends on the day prior to the closing of this offering. We will adjust the amount of our first distribution for the period from the closing of this offering through                     , 2015 based on the number of days in that period.

The table below sets forth the amount of common units and subordinated units that will be outstanding immediately after this offering, assuming the underwriters do not exercise their option to purchase additional common units, and the cash available for distribution needed to pay the aggregate minimum quarterly distribution on all of such units for a single fiscal quarter and a four quarter period:

		Minimum Quarterly Distributions
	Number of Units	One Quarter	Annualized
Common units held by the public(1)		$	$
Common units held by Noble(1)
Subordinated units held by Noble
Total

(1) Assumes no exercise of the underwriters’ option to purchase additional common units. Please read “Use of Proceeds” for a description of the impact of an exercise of the option on the common unit ownership.

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Noble will initially hold all of our incentive distribution rights, which entitle the holder to increasing percentages, up to a maximum of 50%, of the cash we distribute in excess of $     per unit per quarter.

During the subordination period, before we make any quarterly distributions to our subordinated unitholders, our common unitholders are entitled to receive payment of the full minimum quarterly distribution for such quarter plus any arrearages in distributions of the minimum quarterly distribution from prior quarters. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions—Subordinated Units and Subordination Period.” We cannot guarantee, however, that we will pay distributions on our common units at our minimum quarterly distribution rate or at any other rate in any quarter.

Although holders of our common units may pursue judicial action to enforce provisions of our partnership agreement, including those related to requirements to make cash distributions as described above, our partnership agreement provides that any determination made by our general partner in its capacity as our general partner must be made in good faith and that any such determination will not be subject to any other standard imposed by the Delaware Act or any other law, rule or regulation or at equity. Our partnership agreement provides that, in order for a determination by our general partner to be made in “good faith,” our general partner must subjectively believe that the determination is in the best interests of our partnership. In making such determination, our general partner may take into account the totality of the circumstances or the totality of the relationships between the parties involved, including other relationships or transactions that may be particularly favorable or advantageous to us. Please read “Conflicts of Interest and Duties.”

The provision in our partnership agreement requiring us to distribute all of our available cash quarterly may not be modified without amending our partnership agreement; however, as described above, the actual amount of our cash distributions for any quarter is subject to fluctuations based on the amount of cash we generate from our business, the amount of reserves the board of directors of our general partner establishes in accordance with our partnership agreement and the amount of available cash from working capital borrowings.

Additionally, the board of directors of our general partner may reduce the minimum quarterly distribution and the target distribution levels if legislation is enacted or modified that results in our partnership becoming taxable as a corporation or otherwise subject to taxation as an entity for federal, state or local income tax purposes. In such an event, the minimum quarterly distribution and the target distribution levels may be reduced proportionately by the percentage decrease in our available cash resulting from the estimated tax liability we would incur in the quarter in which such legislation is effective. The minimum quarterly distribution will also be proportionately adjusted in the event of any distribution, combination or subdivision of common units in accordance with the partnership agreement, or in the event of a distribution of available cash from capital surplus. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions—Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels.” The minimum quarterly distribution is also subject to adjustment if the holder(s) of the incentive distribution rights (initially only our general partner) elect to reset the target distribution levels related to the incentive distribution rights. In connection with any such reset, the minimum quarterly distribution will be reset to an amount equal to the average cash distribution amount per common unit for the two quarters immediately preceding the reset. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions—Noble’s Right to Reset Incentive Distribution Levels.”

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 September 30, 2016. In those sections, we present two tables, consisting of:

• “Unaudited Pro Forma EBITDA and Distributable Cash Flow for the Year Ended December 31, 2014 and Twelve Months Ended March 31, 2015,” in which we present the amount of EBITDA and distributable cash flow we would have generated on a pro forma basis for the year ended December 31, 2014 and the twelve months ended March 31, 2015, derived from our unaudited pro forma condensed financial statements that are included in this prospectus, as adjusted to give pro forma effect to this offering and the related formation transactions; and

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• “Estimated EBITDA and Distributable Cash Flow for the Twelve Months Ending September 30, 2016,” in which we provide our estimated forecast of our ability to generate sufficient EBITDA and distributable cash flow to pay the minimum quarterly distribution on all common units and subordinated units for the twelve months ending March 31, 2015.

Unless otherwise specifically noted, the amounts set forth in the following sections reflect the pro forma historical and forecasted results attributable to 100% of the assets and operations of our development companies and are not adjusted to reflect Noble’s retained non-controlling interests in our development companies. In connection with the completion of this offering, Noble will contribute to us controlling interests ranging from     % to     % in the development companies that own our Core Assets and Growth Assets, and Noble will retain non-controlling interests ranging from     % to     % in the development companies that own our Core Assets and Growth Assets. Please read “Prospectus Summary—The Transactions” and “Prospectus Summary—Ownership and Organizational Structure.” Following the completion of this offering, we will consolidate the results of operations of our development companies and then record a non-controlling interest deduction for Noble’s retained interests in our development companies.

Unaudited Pro Forma EBITDA and Distributable Cash Flow for the Year Ended December 31, 2014 and Twelve Months Ended March 31, 2015

If we had completed the transactions contemplated in this prospectus on January 1, 2014, pro forma distributable cash flow generated for the year ended December 31, 2014 and the twelve months ended March 31, 2015 would have been approximately $         million and $         million, respectively. These amounts would not have been sufficient to pay the minimum quarterly distribution of $         per unit per quarter ($         per unit on an annualized basis) on all of our common units and subordinated units for each period. 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 the transactions contemplated in this prospectus actually been completed as of the dates indicated. In addition, distributable cash flow is primarily a cash accounting concept, while our unaudited pro forma condensed financial statements 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 been formed on January 1, 2014.

Following the completion of this offering, we estimate that we will incur $         million of incremental annual general and administrative expenses. These incremental general and administrative expenses are not reflected in our unaudited pro forma financial statements and consist of $         million of expenses that we expect to incur as a result of operating as a publicly traded partnership, as well as $         million for the anticipated reimbursement of expenses to our general partner or its affiliates of expenses incurred and payments made on our behalf.

The following table illustrates, on a pro forma basis, for the year ended December 31, 2014 and the twelve months ended March 31, 2015, the amount of cash that would have been available for distribution to our unitholders and our general partner, assuming in each case that this offering and the other transactions contemplated in this prospectus had been consummated on January 1, 2014.

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Noble Midstream Partners LP

Unaudited Pro Forma EBITDA and Distributable Cash Flow

	Year Ended December 31, 2014		Twelve Months Ended March 31, 2015
($ in millions, except per unit amounts)
Revenues
Midstream Services Revenue—Related Party	$		$
Income from Investments
Total Revenue
Expenses
Direct Operating
Depreciation, Depletion and Amortization
General and Administrative(1)
Total Expenses
Operating Income (Loss)
Interest Expense(2)	$		$
Loss Before Income Taxes
Income Tax Benefit
Pro Forma Net Income (Loss)
Less:
Net Income Attributable to Noble-Retained Interests(3)
Net Income Attributable to Noble Midstream Partners LP
Add:
Net Income Attributable to Noble-Retained Interests
Depreciation
Interest Expense
Income Tax Expense
Pro Forma EBITDA
Less:
EBITDA Attributable to Noble-Retained Interests(4)
Pro Forma EBITDA Attributable to Noble Midstream Partners LP
Less:
Cash Interest Expense(5)
Estimated Maintenance Capital Expenditures(6)
Expansion Capital Expenditures(7)
Add:
Capital Contributions from Noble to Fund Expansion Capital Expenditures
Actual Maintenance Capital Expenditures
Pro Forma Distributable Cash Flow Attributable to Noble Midstream Partners LP
Pro Forma Cash Distributions:
Distributions to Public Common Unitholders	$		$
Distributions to Noble:
Common Units Held by Noble
Subordinated Units Held by Noble
Total Distributions to Noble	$		$
Aggregate Quarterly Distributions
Excess / (Shortfall) of Distributable Cash Flow Over Aggregate Annualized Minimum Quarterly Distribution
Percent of Aggregate Annualized Minimum Quarterly Distribution Payable to Common Unitholders		%		%
Percent of Aggregate Annualized Minimum Quarterly Distribution Payable to Subordinated Unitholders		%		%

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(1) We expect to incur approximately $         million of estimated annual incremental general and administrative expenses as a result of being a publicly traded partnership.

(2) Represents non-cash amortization of origination fees and commitment fees on the undrawn portion of our new revolving credit facility that we expect to have in place at the closing of this offering (assuming no amounts have been drawn on the revolving credit facility).

(3) Represents net income attributable to Noble’s non-controlling interests in our development companies.

(4) Represents EBITDA attributable to Noble’s non-controlling interests in our development companies, calculated as follows:

	Year Ended December 31, 2014	Twelve Months Ended March 31, 2015
Less:
Cash Interest Expense(5)
Estimated Maintenance Capital Expenditures(6)
Expansion Capital Expenditures(7)
Add:
Actual Maintenance Capital Expenditures

(5) Represents commitment fees on the undrawn portion of our new revolving credit facility that we expect to have in place at the closing of this offering (assuming no amounts have been drawn on the revolving credit facility).

(6) Represents estimated maintenance capital expenditures attributable to our controlling interests in our development companies. Historically, we did not make a distinction between maintenance capital expenditures and expansion capital expenditures; however, for the purposes of the presentation of “Unaudited Pro Forma EBITDA and Distributable Cash Flow,” we have estimated that approximately $         million and $         million of our capital expenditures would have constituted maintenance capital expenditures for the pro forma year ended December 31, 2014 and the twelve months ended March 31, 2015, respectively. The estimated maintenance capital expenditures attributable to Noble’s retained interests are listed below:

	Year Ended December 31, 2014	Twelve Months Ended March 31, 2015
Maintenance Capital Expenditures Attributable to Noble Midstream Partners LP
Maintenance Capital Expenditures Attributable to Noble—Retained Interest
Total Maintenance Capital Expenditures Attributable to Our Development Companies

(7) Represents estimated expansion capital expenditures attributable to our controlling interests in our development companies. The estimated expansion capital expenditures attributable to Noble’s retained interest are listed below:

	Year Ended December 31, 2014	Twelve Months Ended March 31, 2015
Expansion Capital Expenditures Attributable to Noble Midstream Partners LP
Expansion Capital Expenditures Attributable to Noble—Retained Interest
Total Expansion Capital Expenditures Attributable to Our Development Companies

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Estimated EBITDA and Distributable Cash Flow for the Twelve Months Ending September 30, 2016

We forecast our estimated EBITDA and distributable cash flow for the twelve months ending September 30, 2016 will be approximately $         million and $         million, respectively. In order to pay the aggregate annualized minimum quarterly distribution to all of our unitholders for the twelve months ending September 30, 2016, 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 EBITDA and distributable cash flow for the twelve months ending September 30, 2016, and related assumptions set forth below, to substantiate our belief that we will have sufficient EBITDA and distributable cash flow to pay the aggregate annualized minimum quarterly distribution to all our unitholders for the twelve months ending September 30, 2016. Please read “—Significant Forecast Assumptions.” This forecast is a forward-looking statement and should be read together with our historical and unaudited pro forma 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 forecast was not prepared with a view toward complying with the published guidelines of the SEC or guidelines established by the American Institute of Certified Public Accountants with respect to 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 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 has been prepared by, and is the responsibility of, our management. KPMG LLP has neither compiled nor performed any procedures with respect to the accompanying prospective financial information and, accordingly, KPMG LLP does not express an opinion or any other form of assurance with respect thereto. The KPMG LLP report included in this prospectus 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 EBITDA and distributable cash flow.

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

	September 30, 2016
($ in millions, except per unit amounts)
Revenues
Midstream Services Revenue—Related Party	$
Income from Investments
Total Revenue
Expenses
Direct Operating
General and Administrative(1)
Depreciation, Depletion and Amortization
Total Expenses
Operating Income
Interest Expense(2)
Income Before Income Tax Expense	$
Income Tax Expense
Net Income
Less:
Net Income Attributable to Noble-Retained Interests(3)
Net Income Attributable to Noble Midstream Partners LP	$
Add:
Net Income Attributable to Noble-Retained Interests
Depreciation
Interest Expense
Income Tax Expense
EBITDA	$
Less:
EBITDA Attributable to Noble-Retained Interests(4)	$
EBITDA Attributable to Noble Midstream Partners LP	$
Less:
Cash Interest Expense(5)	$
Estimated Maintenance Capital Expenditures(6)
Expansion Capital Expenditures(7)
Add:
Actual Maintenance Capital Expenditures
Borrowings to Fund Expansion Capital Expenditures
Cash Used to Fund Expansion Capital Expenditures
Estimated Distributable Cash Flow Attributable to Noble Midstream Partners LP	$
Distributions to Public Common Unitholders	$
Distributions to Noble:
Common Units Held by Noble
Subordinated Units Held by Noble
Total Distributions to Noble	$
Aggregate Quarterly Distributions
Excess of Distributable Cash Flow Over Aggregate Annualized Minimum Quarterly Distribution

(1) We expect to incur approximately $         million of estimated annual incremental general and administrative expenses as a result of being a publicly traded partnership, of which approximately $         million is included in General and Administrative—Third Party and approximately $         million is included in General and Administrative—Related Party.

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(2) Forecasted interest expense includes (i) interest on amounts outstanding under our new revolving credit facility; (ii) amortization of origination fees and (iii) commitment fees on the unused portion of our new revolving credit facility.

(3) Represents net income attributable to Noble’s non-controlling interests in our development companies.

(4) Represents EBITDA attributable to Noble’s non-controlling interests in our development companies, calculated as follows:

Net income attributable to Noble’s non-controlling interests in our development companies	$
Add:
Depreciation expense attributable to Noble’s non-controlling interests in our development companies
EBITDA attributable to Noble’s non-controlling interests in our development companies	$

(5) Forecasted cash interest expense includes (i) interest on amounts outstanding under our new revolving credit facility and (ii) commitment fees on the unused portion of our new revolving credit facility.

(6) Represents estimated maintenance capital expenditures attributable to our controlling interests in our development companies. The estimated maintenance capital expenditures attributable to Noble’s retained interests are listed below:

Maintenance Capital Expenditures Attributable to Noble Midstream Partners LP	$
Maintenance Capital Expenditures Attributable to Noble—Retained Interest
Total Maintenance Capital Expenditures Attributable to Our Development Companies	$

(7) Represents estimated expansion capital expenditures attributable to our controlling interests in our development companies. The estimated expansion capital expenditures attributable to Noble’s retained interest are listed below:

Expansion Capital Expenditures Attributable to Noble Midstream Partners LP	$
Expansion Capital Expenditures Attributable to Noble—Retained Interest
Total Expansion Capital Expenditures Attributable to Our Development Companies	$

Significant Forecast Assumptions

The forecast has been prepared by and is the responsibility of management. The forecast reflects our judgment as of the date of this prospectus of conditions we expect to exist and the course of action we expect to take during the twelve months ending September 30, 2016. 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.

General Considerations

Our Predecessor’s historical results of operations include all of the results of operations of Noble Midstream LP Predecessor on a 100% basis, which includes 100% of the results of our each of our development companies, in which we own percentages varying from     % to     %. See “Business—Our Existing Assets.” In connection with the completion of this offering, Noble will contribute to us a     % controlling interest in the development company that owns our Core Assets other than our 3.33% ownership interest in White Clifts LLC, which we wholly own, and     %,     %,     % and     % controlling interests in the development companies that own our Growth Assets. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Factors Affecting the Comparability of Our Financial Results” and “Certain Relationships and Related Party Transactions—Agreements with our Affiliates in Connection with the Transactions—Contribution Agreement.” Substantially all of our revenue will be derived from long-term, fixed-fee gathering agreements with Noble.

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Results, Volumes and Fees

The following table summarizes the pro forma revenues, volumes, fees and EBITDA for our midstream services for the year ended December 31, 2014 and the twelve months ended March 31, 2015, as well as our forecast regarding those same amounts for the twelve months ending September 30, 2016.

	Pro Forma  Year Ended December 31, 2014	Pro Forma Twelve Months Ended March 31, 2015	Forecasted Twelve Months Ending September 30, 2016
Crude oil gathering volumes (Bbl/d)
Crude oil gathering fees ($/Bbl)(1)	$	$	$
Crude oil treating fees
Natural gas gathering volumes (MMBtu/d)
Natural gas gathering fees ($/MMBtu)(1)	$	$	$
Fresh water services volumes (Bbl/d)
Fresh water services fee ($/Bbl)	$	$	$
Saltwater services volumes (Bbl/d)	$	$	$
Saltwater services fees ($/Bbl)	$	$	$
Total Revenues ($ in millions)	$	$	$
EBITDA ($ in millions)	$	$	$

(1) Represents the weighted average per unit.

Revenue

We estimate that total revenues for the twelve months ending September 30, 2016 will be approximately $         million compared to approximately $         million for the pro forma year ended December 31, 2014 and approximately $         million for the pro forma twelve months ended March 31, 2015, primarily due to increased throughput on our gathering systems. Noble forecasts connecting to our infrastructure, and commencing production on, over             lateral feet on our dedicated acreage during the twelve months ending September 30, 2016. As a result of these additional wells, in addition to production from existing wells on our systems, we estimate that our average daily throughput for the twelve months ending September 30, 2016 will be             MBoe/d of             and             MBoe/d of             . Our forecasted increase in volumes over the pro forma twelve months ended March 31, 2015 is based on our expectation that Noble will complete the drilling and development activities on our dedicated acreage consistent with their current drilling and development plan. Under our commercial agreements, we forecast that we will receive a fee of $        . Please read “Business—Our Commercial Agreements with Noble.”

Operating Expense

We estimate that total operating expense for the twelve months ending September 30, 2016 will be $         million compared to approximately $         million for the pro forma year ended December 31, 2014 and approximately $         million for the pro forma twelve months ended March 31, 2015. Our increase in operating expense is primarily due to our significantly higher operating levels, resulting in higher:

• gathering throughput on our dedicated acreage;

• maintenance and contract service costs;

• regulatory and compliance costs;

• operating costs associated with increased pipeline mileage and additional centralized gathering facilities; and

• ad valorem taxes.

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General and Administrative Expenses

Our general and administrative expenses will consist of (i) direct general and administrative expenses incurred by us, (ii) allocated general administrative expenses from Noble and (iii) fixed-fee payments we make to Noble for the provision of general and administrative services under our omnibus agreement.

We expect total general and administrative expenses for the twelve months ending September 30, 2016 will be $         million as compared to $         million for the pro forma year ended December 31, 2014 and approximately $         million for the pro forma twelve months ended March 31, 2015. These amounts include the $         million of annual incremental publicly traded partnership expenses we expect to incur. The increase in general and administrative expenses primarily relates to increased personnel and associated administrative expenses due to our projected growth.

Depreciation

We estimate that depreciation for the twelve months ending September 30, 2016 will be $         million as compared to approximately $         million for the pro forma year ended December 31, 2014 and approximately $         million for the pro forma twelve months ending March 31, 2015. Our expected increase is primarily attributable to the effect of             and depreciation on the new infrastructure constructed and to be constructed during the twelve months ending September 30, 2016.

Capital Expenditures

The midstream energy business is capital intensive, requiring the maintenance of existing gathering systems and other midstream assets and facilities and the acquisition or construction and development of new gathering systems and other midstream assets and facilities. Our partnership agreement will require that we categorize our capital expenditures as either:

• Estimated maintenance capital expenditures, which are cash expenditures (including expenditures for the construction or development of new capital assets or the replacement, improvement or expansion of existing capital assets) made to maintain, over the long term, our 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 to the extent such capital expenditures are necessary to maintain, over the long term, our operating capacity, operating income or revenue; or

• Expansion capital expenditures, which are cash expenditures 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 throughput. Examples of expansion capital expenditures include the construction, development or acquisition of additional gathering pipelines and centralized gathering facilities, in each case to the extent such capital expenditures are expected to expand our operating capacity, operating income or revenue. In the future, if we make acquisitions that increase system throughput or capacity, the associated capital expenditures may also be considered expansion capital expenditures.

We generally categorize specific capital expenditures as either expansion capital expenditures or maintenance capital expenditures based on the nature of the expenditure. However, a portion of our capital expenditures relate to the connection of our gathering systems to new wells. While these capital expenditures could generally be considered expansion capital expenditures because they will result in increased throughput or cash flows produced by our midstream systems, we categorize a portion of these capital expenditures as

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maintenance capital expenditures because they are necessary to offset the natural production declines Noble will experience on all of its wells over time.

In allocating expenditures between maintenance capital expenditures and expansion capital expenditures for new well connections during the twelve months ending September 30, 2016, we first estimate the number of new well connections needed to offset the natural production decline and maintain the average throughput volume on our systems during the forecast period. We then allocate to maintenance capital the estimated new well connection expenditures based on a per well connection cost estimate. We estimate that total capital expenditures attributable to our development companies for the twelve months ending September 30, 2016 will be $         million ($         million net to our ownership interests in our development companies) based on the following assumptions.

Because Noble has retained a non-controlling interest in each of the development companies that hold our assets, Noble will be required to fund its allocable portion of our maintenance and expansion capital expenditures. See “Risk Factors—Risks Inherent in an Investment in Us—Our general partner and its affiliates, including Noble, have conflicts of interest with us and limited fiduciary duties to us and our unitholders, and they may favor their own interests to our detriment and that of our unitholders. Additionally, we have no control over the business decisions and operations of Noble, and Noble is under no obligation to adopt a business strategy that favors us.”

We estimate that maintenance capital expenditures will be $         million ($         million net to our ownership interests in our development companies) for the twelve months ending September 30, 2016. We expect to fund our allocated portion of these maintenance capital expenditures with cash generated by our operations. Because our midstream 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 September 30, 2016 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 offset the natural production declines Noble will experience on all of their wells over time. The methodology we use to categorize these capital expenditures is described above.

Expansion Capital Expenditures

We estimate that expansion capital expenditures for the twelve months ending September 30, 2016 will be $         million ($         million net to our ownership interests in our development companies). During the twelve months ending September 30, 2016, 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 Noble’s drilling and completion schedule and increasing production on our dedicated acreage. A majority of Noble’s planned well completions and production growth on our dedicated acreage during the twelve months ending September 30, 2016 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 September 30, 2016:

• Crude oil gathering: We expect to spend approximately $         million in expansion capital expenditures (net to our ownership interests in our development companies) related to                     .

• Natural gas gathering: We expect to spend approximately $         million in expansion capital expenditures (net to our ownership interests in our development companies) related to                     .

• Saltwater gathering: We expect to spend approximately $         million in expansion capital expenditures (net to our ownership interests in our development companies) related to                     .

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• Fresh water delivery: We expect to spend approximately $         million in expansion capital expenditures (net to our ownership interests in our development companies) related to                     .

Regulatory, Industry and Economic Factors

Our forecast of EBITDA and distributable cash flow for the twelve months ending September 30, 2016 is also based on the following significant assumptions related to regulatory, industry and economic factors:

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

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

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

• there will not be a shortage of skilled labor; and

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

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PROVISIONS OF OUR PARTNERSHIP AGREEMENT RELATING TO CASH DISTRIBUTIONS

Set forth below is a summary of the significant provisions of our partnership agreement that relate to cash distributions.

Distributions of Available Cash

General

Our partnership agreement requires that, within 45 days after the end of each quarter, beginning with the quarter ending                     , 2015, we distribute all of our available cash to unitholders of record on the applicable record date. We will adjust the amount of our distribution for the period from the closing of this offering through                     , 2015, based on the actual length of the period.

Definition of Available Cash

Available cash generally means, for any quarter, all cash and cash equivalents on hand at the end of that quarter:

• less, the amount of cash reserves established by our general partner to:

• provide for the proper conduct of our business (including reserves for our future capital expenditures, future acquisitions and anticipated future debt service requirements);

• comply with applicable law or any loan agreement, security agreement, mortgage, debt instrument or other agreement or obligation to which we or any of our subsidiaries is a party or by which we or such subsidiary is bound or we or such subsidiary’s assets are subject; or

• provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters (provided that our general partner may not establish cash reserves for distributions pursuant to this bullet point if the effect of such reserves will prevent us from distributing the minimum quarterly distribution on all common units and any cumulative arrearages on such common units for the current quarter);

• plus, if our general partner so determines, all or any portion of the cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made subsequent to the end of such quarter.

The purpose and effect of the last bullet point above is to allow our general partner, if it so decides, to use cash from working capital borrowings made after the end of the quarter but on or before the date of determination of available cash for that quarter to pay distributions to unitholders. Under our partnership agreement, working capital borrowings are generally borrowings incurred under a credit facility, commercial paper facility or similar financing arrangement that are used solely for working capital purposes or to pay distributions to our partners and with the intent of the borrower to repay such borrowings within twelve months with funds other than from additional working capital borrowings. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Capital Resources and Liquidity—Revolving Credit Facility.”

Intent to Distribute the Minimum Quarterly Distribution

Under our current cash distribution policy, we intend to make a minimum quarterly distribution to the holders of our common units and subordinated units of $         per unit, or $         per unit on an annualized basis, to the extent we have sufficient available cash after the establishment of cash reserves and the payment of costs and expenses, including reimbursements of expenses to our general partner. However, there is no guarantee that

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we will pay the minimum quarterly distribution on our units in any quarter. The amount of distributions paid under our cash distribution policy and the decision to make any distribution will be determined by our general partner, taking into consideration the terms of our partnership agreement.

General Partner Interest

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 securities in us that will entitle it to receive distributions.

Incentive Distribution Rights

Noble currently holds incentive distribution rights that entitle it to receive increasing percentages, up to a maximum of 50%, of the available cash we distribute from operating surplus (as defined below) in excess of $         per unit per quarter. The maximum distribution of 50% does not include any distributions that Noble or its affiliates may receive on common units or subordinated units that it owns.

Operating Surplus and Capital Surplus

General

All cash distributed to unitholders will be characterized as either being paid from “operating surplus” or “capital surplus.” We treat distributions of available cash from operating surplus differently than distributions of available cash from capital surplus.

Operating Surplus

We define operating surplus as:

• $         million (as described below); plus

• all of our cash receipts after the closing of this offering, excluding cash from interim capital transactions (as defined below) and the termination of hedge contracts, provided that cash receipts from the termination of a commodity hedge or interest rate hedge prior to its scheduled settlement or termination date shall be included in operating surplus in equal quarterly installments over the remaining scheduled life of such commodity hedge or interest rate hedge; plus

• working capital borrowings made after the end of a quarter but on or before the date of determination of operating surplus for that quarter; plus

• cash distributions (including incremental distributions on incentive distribution rights) paid in respect of equity issued, other than equity issued in this offering, to finance all or a portion of expansion capital expenditures in respect of the period from the date that we enter into a binding obligation to commence the construction, development, replacement, improvement or expansion of a capital asset and ending on the earlier to occur of the date the capital asset commences commercial service and the date that it is abandoned or disposed of; less

• all of our operating expenditures (as defined below) after the closing of this offering; less

• the amount of cash reserves established by our general partner to provide funds for future operating expenditures; less

• all working capital borrowings not repaid within twelve months after having been incurred, or repaid within such twelve-month period with the proceeds of additional working capital borrowings.

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As described above, operating surplus does not reflect actual cash on hand that is available for distribution to our unitholders and is not limited to cash generated by operations. For example, it includes a provision that will enable us, if we choose, to distribute as operating surplus up to $         million of 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 repayments are made. However, if working capital borrowings, which increase operating surplus, are not repaid during the twelve-month period following the borrowing, they will be deemed repaid at the end of such period, thus decreasing operating surplus at such time. When such working capital borrowings are in fact repaid, they will not be treated as a further reduction in operating surplus because operating surplus will have been previously reduced by the deemed repayment.

We define interim capital transactions as (i) borrowings, refinancings or refundings of indebtedness (other than working capital borrowings and items purchased on open account or for a deferred purchase price in the ordinary course of business) and sales of debt securities, (ii) sales of equity securities and (iii) sales or other dispositions of assets, other than sales or other dispositions of inventory, accounts receivable and other assets in the ordinary course of business and sales or other dispositions of assets as part of normal asset retirements or replacements.

We define operating expenditures as all of our cash expenditures, including, but not limited to, taxes, reimbursements of expenses of our general partner and its affiliates, officer, director and employee compensation, debt service payments, payments made in the ordinary course of business under interest rate hedge contracts and commodity hedge contracts (provided that payments made in connection with the termination of any interest rate hedge contract or commodity hedge contract prior to its scheduled settlement or termination 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 and amounts paid in connection with the initial purchase of an interest rate hedge contract or a commodity hedge contract will be amortized over the life of such interest rate hedge contract or commodity hedge contract), estimated maintenance capital expenditures (as discussed in further detail below), and repayment of working capital borrowings; provided, however, that operating expenditures will not include:

• repayments of working capital borrowings where such borrowings have previously been deemed to have been repaid (as described above);

• payments (including prepayments and prepayment penalties) of principal of and premium on indebtedness other than working capital borrowings;

• actual maintenance capital expenditures;

• expansion capital expenditures;

• payment of transaction expenses (including taxes) relating to interim capital transactions;

• distributions to our partners;

• repurchases of partnership interests (excluding repurchases we make to satisfy obligations under employee benefit plans); or

• any other expenditures or payments using the proceeds from this offering that are described in “Use of Proceeds.”

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Capital Surplus

Capital surplus is defined in our partnership agreement as any distribution of available cash in excess of our cumulative operating surplus. Accordingly, except as described above, capital surplus would generally be generated by:

• borrowings other than working capital borrowings;

• sales of our equity and debt securities;

• sales or other dispositions of assets, other than inventory, accounts receivable and other assets sold in the ordinary course of business or as part of ordinary course retirement or replacement of assets; and

• capital contributions received.

Characterization of Cash Distributions

All available cash distributed by us on any date from any source will be treated as distributed from operating surplus until the sum of all available cash distributed by us since the closing of this offering equals the operating surplus from the closing of this offering through the end of the quarter immediately preceding that distribution. We anticipate that distributions from operating surplus generally will not represent a return of capital. However, operating surplus, as defined in our partnership agreement, includes certain components, including a $         million cash basket, that represent non-operating sources of cash. Consequently, it is possible that all or a portion of specific distributions from operating surplus may represent a return of capital. Any available cash distributed by us in excess of our cumulative operating surplus will be deemed to be capital surplus under our partnership agreement. Our partnership agreement treats a distribution of capital surplus as the repayment of the initial unit price from this initial public offering and as a return of capital. We do not anticipate that we will make any distributions from capital surplus.

Capital Expenditures

For purposes of determining operating surplus, maintenance capital expenditures are those capital expenditures required to maintain our long-term operating capacity or operating income, and expansion capital expenditures are those capital expenditures that we expect will expand our operating capacity or operating income over the long term. Examples of maintenance capital expenditures include capital expenditures associated with the replacement of equipment and well connections, or the construction, development or acquisition of other facilities, to replace expected reductions in hydrocarbons available for gathering, treating, transporting or otherwise handled by our facilities (which we refer to as operating capacity). Maintenance capital expenditures will also include interest (and related fees) on debt incurred and distributions on equity issued to finance all or any portion of the construction, improvement or replacement of an asset that is paid in respect of the period that begins when we enter into a binding obligation to commence constructing or developing a replacement asset and ending on the earlier to occur of the date of any such replacement asset commences commercial service or the date that it is abandoned or disposed of. Capital expenditures made solely for investment purposes will not be considered maintenance capital expenditures.

Because our maintenance capital expenditures can be irregular, the amount of our actual maintenance capital expenditures may differ substantially from period to period, which could cause similar fluctuations in the amounts of operating surplus, adjusted operating surplus and cash available for distribution to our unitholders if we subtracted actual maintenance capital expenditures from operating surplus.

Our partnership agreement will require that an estimate of the average quarterly maintenance capital expenditures necessary to maintain our operating capacity or operating income over the long term be subtracted from operating surplus each quarter as opposed to the actual amounts spent. The amount of estimated maintenance capital expenditures deducted from operating surplus for those periods will be subject to review and

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change by our general partner at least once a year, provided that any change is approved by our special committee. The estimate will be made at least annually and whenever an event occurs that is likely to result in a material adjustment to the amount of our maintenance capital expenditures, such as a major acquisition or the introduction of new governmental regulations that will impact our business. For purposes of calculating operating surplus, any adjustment to this estimate will be prospective only. For a discussion of the amounts we have allocated toward estimated maintenance capital expenditures, please read “Cash Distribution Policy and Restrictions on Distributions.”

The use of estimated maintenance capital expenditures in calculating operating surplus will have the following effects:

• it will reduce the risk that maintenance capital expenditures in any one quarter will be large enough to render operating surplus less than the initial quarterly distribution to be paid on all the units for the quarter and subsequent quarters;

• it will increase our ability to distribute as operating surplus cash we receive from non-operating sources; and

• it will be more difficult for us to raise our distribution above the minimum quarterly distribution and pay incentive distributions on the incentive distribution rights held by our general partner.

Expansion capital expenditures are cash expenditures 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 throughput. Examples of expansion capital expenditures include the construction, development or acquisition of additional gathering pipelines and centralized gathering facilities, in each case to the extent such capital expenditures are expected to expand our operating capacity, operating income or revenue. In the future, if we make acquisitions that increase system throughput or capacity, the associated capital expenditures may also be considered expansion capital expenditures.

Capital expenditures that are made in part for maintenance capital purposes and in part for expansion capital purposes will be allocated as maintenance capital expenditures or expansion capital expenditures by our general partner.

Subordinated Units and Subordination Period

General

Our partnership agreement provides that, during the subordination period (which we define below), the common units will have the right to receive distributions of available cash from operating surplus each quarter in an amount equal to $         per 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 of available cash from operating surplus may be made on the subordinated units. Subordinated 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 until the common units have received the minimum quarterly distribution plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters. Furthermore, no arrearages will accrue or be payable on the subordinated units. The practical effect of the subordinated units is to increase the likelihood that, during the subordination period, there will be available cash to be distributed on the common units.

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Subordination Period

Except as described below, the subordination period will begin on the closing date of this offering and will extend until the first business day following the distribution of available cash in respect of any quarter beginning after                     , 2018, that each of the following tests are met:

• distributions of available cash from operating surplus on each of the outstanding common units and subordinated units equaled or exceeded $         (the annualized minimum quarterly distribution), for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date;

• the adjusted operating surplus (as defined below) generated during each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of $         (the annualized minimum quarterly distribution) on all of the outstanding common units and subordinated units during those periods on a fully diluted basis; and

• there are no arrearages in payment of the minimum quarterly distribution on the common units.

Early Termination of the Subordination Period

Notwithstanding the foregoing, the subordination period will automatically terminate on the first business day following the distribution of available cash in respect of any quarter, beginning with the quarter ending                     , 2016, that each of the following tests are met:

• distributions of available cash from operating surplus on each of the outstanding common units and subordinated units equaled or exceeded $         (150% of the annualized minimum quarterly distribution), plus the related distributions on the incentive distribution rights, for the four-quarter period immediately preceding that date;

• the adjusted operating surplus (as defined below) generated during the four-quarter period immediately preceding that date equaled or exceeded the sum of (i) $         (150% of the annualized minimum quarterly distribution) on all of the outstanding common units and subordinated units during that period on a fully diluted basis and (ii) the corresponding distributions on the incentive distribution rights; and

• there are no arrearages in payment of the minimum quarterly distribution on the common units.

Expiration of the Subordination Period

When the subordination period ends, each outstanding subordinated unit will convert into one common unit and will thereafter participate pro rata with the other common units in distributions of available cash.

Adjusted Operating Surplus

Adjusted operating surplus is intended to reflect the cash generated from operations during a particular period and therefore excludes net drawdowns of reserves of cash established in prior periods. Adjusted operating surplus for a period consists of:

• operating surplus generated with respect to that period (excluding any amounts attributable to the item described in the first bullet under the caption “—Operating Surplus and Capital Surplus—Operating Surplus” above); less

• any net increase in working capital borrowings with respect to that period; less

• any net decrease in cash reserves for operating expenditures with respect to that period not relating to an operating expenditure made with respect to that period; plus

• any net decrease in working capital borrowings with respect to that period; plus

• any net decrease made in subsequent periods to cash reserves for operating expenditures initially established with respect to that period to the extent such decrease results in a reduction in adjusted operating surplus in subsequent periods; plus

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• any net increase in cash reserves for operating expenditures with respect to that period required by any debt instrument for the repayment of principal, interest or premium.

Distributions of Available Cash from Operating Surplus During the Subordination Period

We will make distributions of available cash from operating surplus for any quarter during the subordination period in the following manner:

• first, 100% to the common unitholders, pro rata, until we distribute for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter;

• second, 100% to the common unitholders, pro rata, until we distribute for each outstanding common unit an amount equal to any arrearages in payment of the minimum quarterly distribution on the common units for any prior quarters during the subordination period;

• third, 100% to the subordinated unitholders, pro rata, until we distribute for each outstanding subordinated unit an amount equal to the minimum quarterly distribution for that quarter; and

• thereafter, in the manner described in “—Incentive Distribution Rights” below.

The preceding discussion is based on the assumptions that we do not issue additional classes of equity securities.

Distributions of Available Cash from Operating Surplus After the Subordination Period

We will make distributions of available cash from operating surplus for any quarter after the subordination period in the following manner:

• first, 100% to all common unitholders, pro rata, until we distribute for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter; and

• thereafter, in the manner described in “—Incentive Distribution Rights” below.

The preceding discussion is based on the assumptions that we do not issue additional classes of equity securities.

Incentive Distribution Rights

Incentive distribution rights represent the right to receive an increasing percentage (15%, 25% and 50%) of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved. Noble will initially hold the incentive distribution rights, but may transfer these rights separately from its ownership of the general partner.

The following discussion assumes Noble continues to own the incentive distribution rights.

If for any quarter:

• we have distributed available cash from operating surplus to the common unitholders and subordinated unitholders in an amount equal to the minimum quarterly distribution; and

• we have distributed available cash from operating surplus on outstanding common units in an amount necessary to eliminate any cumulative arrearages in payment of the minimum quarterly distribution;

then, we will distribute any additional available cash from operating surplus for that quarter among the unitholders and our general partner in the following manner:

• first, 100% to all unitholders, pro rata, until each unitholder receives a total of $         per unit for that quarter (the “first target distribution”);

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• second, 85% to all unitholders, pro rata, and 15% to the holders of our incentive distribution rights, until each unitholder receives a total of $         per unit for that quarter (the “second target distribution”);

• third, 75% to all unitholders, pro rata, and 25% to the holders of our incentive distribution rights, until each unitholder receives a total of $         per unit for that quarter (the “third target distribution”); and

• thereafter, 50% to all unitholders, pro rata, and 50% to the holders of our incentive distribution rights.

Percentage Allocations of Available Cash from Operating Surplus

The following table illustrates the percentage allocations of available cash from operating surplus between the unitholders and our general partner based on the specified target distribution levels. The amounts set forth under “Marginal Percentage Interest in Distributions” are the percentage interests of Noble, as holder of our incentive distribution rights, and the unitholders in any available cash from operating surplus we distribute up to and including the corresponding amount in the column “Total Quarterly Distribution Per Unit Target Amount.” The percentage interests shown for our unitholders Noble 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 that Noble has not transferred its incentive distribution rights and that there are no arrearages on common units.

			Marginal Percentage Interest in Distributions
	Total Quarterly  Distribution Per Unit Target Amount		Unitholders			Noble (as Holder of the Incentive Distribution Rights)(1)
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	%

(1) Does not account for any common units or subordinated units that Noble owns.

Noble’s Right to Reset Incentive Distribution Levels

Noble, as the initial holder of our incentive distribution rights, has the right under our partnership agreement, subject to certain conditions, 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 minimum quarterly distribution amount and target distribution levels upon which the incentive distribution payments to our general partner would be set. If Noble 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 Noble holds all of the incentive distribution rights at the time that a reset election is made. Noble’s right to reset the minimum quarterly distribution amount and the target distribution levels upon which the incentive distributions payable to Noble are based may be exercised, without approval of our unitholders or the conflicts committee, at any time when there are no subordinated units outstanding, we have made cash distributions to the holders of the incentive distribution rights at the highest level of incentive distributions for each of the four consecutive fiscal quarters immediately preceding such time and the amount of each such distribution did not exceed adjusted operating surplus for such quarter. If Noble and its affiliates are not the holders of a majority of the incentive distribution rights at the time an election is made to reset the minimum quarterly distribution amount and the target distribution levels, then the proposed reset will be subject to the prior written concurrence of the general partner that the conditions described above have been satisfied. The reset minimum quarterly distribution amount and target distribution levels will be higher than the minimum quarterly distribution amount and the target distribution levels prior to the reset such that the holder of the

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incentive distribution rights will not receive any incentive distributions under the reset target distribution levels until cash distributions per unit following this event increase as described below. We anticipate that Noble 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 to our general partner.

In connection with the resetting of the minimum quarterly distribution amount and the target distribution levels and the corresponding relinquishment by Noble of incentive distribution payments based on the target distributions prior to the reset, Noble will be entitled to receive a number of newly issued common units based on a predetermined formula described below that takes into account the “cash parity” value of the average cash distributions related to the incentive distribution rights received by Noble for the two quarters immediately preceding the reset event as compared to the average cash distributions per common unit during that two-quarter period.

The number of common units that Noble (or the then-holder of the incentive distribution rights, if other than our general partner) would be entitled to receive from us in connection with a resetting of the minimum quarterly distribution amount and the target distribution levels then in effect would be equal to the quotient determined by dividing (x) the average aggregate amount of cash distributions received by Noble or such holder in respect of its incentive distribution rights during the two consecutive fiscal quarters ended immediately prior to the date of such reset election by (y) the average of the aggregate amount of cash distributed per common unit during each of these two quarters.

Following a reset election, the minimum quarterly distribution amount will be reset to an amount equal to the average cash distribution amount per common unit for the two fiscal quarters 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 distribute all of our available cash from operating surplus for each quarter thereafter as follows:

• first, 100% to all unitholders, pro rata, until each unitholder receives an amount equal to 115% of the reset minimum quarterly distribution for that quarter;

• second, 85% to all unitholders, pro rata, and 15% to the holders of our incentive distribution rights, until each unitholder receives an amount per unit equal to 125% of the reset minimum quarterly distribution for the quarter;

• third, 75% to all unitholders, pro rata, and 25% to the holders of our incentive distribution rights, until each unitholder receives an amount per unit equal to 150% of the reset minimum quarterly distribution for the quarter; and

• thereafter, 50% to all unitholders, pro rata, and 50% to the holders of our incentive distribution rights.

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The following table illustrates the percentage allocations of available cash from operating surplus between the unitholders and Noble at various cash distribution levels (1) pursuant to the cash distribution provisions of our partnership agreement in effect at the completion of this offering, as well as (2) following a hypothetical reset of the minimum quarterly distribution and target distribution levels based on the assumption that the average quarterly cash distribution amount per common unit during the two fiscal quarters immediately preceding the reset election was $        .

				Common Unitholders			Noble (as holder of the  Incentive Distribution Rights)			Quarterly  Distribution Per Unit Following Hypothetical Reset
	Quarterly Distribution Per  Unit Prior to Reset
Minimum Quarterly Distribution			$		100	%		—			$
First Target Distribution	above $	up to $			100	%		—		above $	up to $	(a)
Second Target Distribution	above $	up to $			85	%		15	%	above $	up to $	(b)
Third Target Distribution	above $	up to $			75	%		25	%	above $ $	up to	(c)
Thereafter		above $			50	%		50	%		above $	(c)

(a) This amount is 115% of the hypothetical reset minimum quarterly distribution.

(b) This amount is 125% of the hypothetical reset minimum quarterly distribution.

(c) This amount is 150% of the hypothetical reset minimum quarterly distribution.

The following table illustrates the total amount of available cash from operating surplus that would be distributed to the unitholders and Noble including in respect of incentive distribution rights, based on an average of the amounts distributed for the two quarters immediately prior to the reset. The table assumes that immediately prior to the reset there would be             common units outstanding and the average distribution to each common unit would be $         per quarter for the two consecutive, non-overlapping quarters prior to the reset.

	Quarterly Distribution Per Unit Prior to Reset		Cash Distributions to Common Unitholders Prior to Reset	Cash Distribution to Noble Prior to Reset					Total Distributions
				Common Units		Incentive Distribution Rights		Total
Minimum Quarterly Distribution		$	$	$	—	$	—	$	$
First Target Distribution	above $	up to $			—		—
Second Target Distribution	above $	up to $			—
Third Target Distribution	above $	up to $			—
Thereafter		above $			—
			$	$	—	$		$	$

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The following table illustrates the total amount of available cash from operating surplus that would be distributed to the unitholders and Noble, with respect to the quarter after the reset occurs. The table reflects that, as a result of the reset, there would be             common units outstanding and that the average distribution to each common unit would be $        . The number of common units issued as a result of the reset was calculated by dividing (x) $         as the average of the amounts received by the general partner in respect of its incentive distribution rights for the two consecutive, non-overlapping quarters prior to the reset as shown in the table above, by (y) the average of the cash distributions made on each common unit per quarter for the two consecutive, non-overlapping quarters prior to the reset as shown in the table above, or $        .

	Quarterly Distribution Per Unit Prior to Reset		Cash Distributions to Common Unitholders Prior to  Reset	Cash Distribution to Noble Prior to Reset					Total Distributions
				Common Units		Incentive Distribution Rights		Total
Minimum Quarterly Distribution		$	$	$	—	$	—	$	$
First Target Distribution	above $	up to $			—		—
Second Target Distribution	above $	up to $			—
Third Target Distribution	above $	up to $			—
Thereafter		above $			—
			$	$	—	$		$	$

Noble will be entitled to cause the minimum quarterly distribution amount and the target distribution levels to be reset on more than one occasion, provided that it may not make a reset election except at a time when it has received incentive distributions for the immediately preceding four consecutive fiscal quarters based on the highest level of incentive distributions that it is entitled to receive under our partnership agreement.

Distributions from Capital Surplus

How Distributions from Capital Surplus Will Be Made

We will make distributions of available cash from capital surplus, if any, in the following manner:

• first, 100% to all unitholders, pro rata, until we distribute for each common unit that was issued in this offering, an amount of available cash from capital surplus equal to the initial public offering price in this offering;

• second, 100% to all unitholders, pro rata, until we distribute for each common unit, an amount of available cash from capital surplus equal to any unpaid arrearages in payment of the minimum quarterly distribution on the outstanding common units; and

• thereafter, as if they were from operating surplus.

Effect of a Distribution from Capital Surplus

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

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Once we distribute capital surplus on a unit issued in this offering in an amount equal to the initial unit price, we will reduce the minimum quarterly distribution and the target distribution levels to zero. Then, after distributing an amount of capital surplus for each common unit equal to any unpaid arrearages of the minimum quarterly distributions on outstanding common units, we will then make all future distributions from operating surplus, with 50% being paid to the unitholders, pro rata, and 50% to the holder of our incentive distribution rights.

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 of capital surplus, if we combine our units into fewer units or subdivide our units into a greater number of units, we will proportionately adjust:

• the minimum quarterly distribution;

• target distribution levels;

• the unrecovered initial unit price; and

• the arrearages per common unit in payment of the minimum quarterly distribution on the common units.

For example, if a two-for-one split of the common units should occur, the minimum quarterly distribution, the target distribution levels and the unrecovered initial unit price would each be reduced to 50% of its initial level and each subordinated unit would be split into two units. We will not make any adjustment by reason of the issuance of additional units for cash or property (including additional common units issued under any compensation or benefit plans).

In addition, if legislation is enacted or if the official interpretation of existing law is modified by a governmental authority, so that we become taxable as a corporation or otherwise subject to taxation as an entity for federal, state or local income tax purposes, our partnership agreement specifies that the minimum quarterly distribution and the target distribution levels for each quarter may be reduced by multiplying each distribution level by a fraction, the numerator of which is available cash for that quarter (reduced by the amount of the estimated tax liability for such quarter payable by reason of such legislation or interpretation) and the denominator of which is the sum of available cash for that quarter (reduced by the amount of the estimated tax liability for such quarter payable by reason of such legislation or interpretation) plus our general partner’s estimate of our aggregate liability for the quarter for such income taxes payable by reason of such legislation or interpretation. To the extent that the actual tax liability differs from the estimated tax liability for any quarter, the difference may be accounted for in subsequent quarters.

Distributions of Cash Upon Liquidation

General

If we dissolve in accordance with our 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 our general partner, 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 outstanding common units to a preference over the holders of outstanding subordinated units upon our liquidation, to the extent required to permit common unitholders to receive their unrecovered 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

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sufficient gain upon our liquidation to enable the holders of common units 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.

Manner of Adjustments for Gain

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

• first, to our general partner to the extent of any negative balance in its capital account;

• second, 100% to the common unitholders, pro rata, until the capital account for each common unit is equal to the sum of:

(1) the unrecovered initial unit price;

(2) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs; and

(3) any unpaid arrearages in payment of the minimum quarterly distribution;

• third, 100% to the subordinated unitholders, pro rata, until the capital account for each subordinated unit is equal to the sum of:

(1) the unrecovered initial unit price; and

(2) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs;

• fourth, 100% to all unitholders, pro rata, until we allocate under this paragraph an amount per unit equal to:

(1) the sum of the excess of the first target distribution per unit over the minimum quarterly distribution per unit for each quarter of our existence; less

(2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the minimum quarterly distribution per unit that we distributed 100% to the unitholders, pro rata, for each quarter of our existence;

• fifth, 85% to all unitholders, pro rata, and 15% to the holders of our incentive distribution rights, until we allocate under this paragraph an amount per unit equal to:

(1) the sum of the excess of the second target distribution per unit over the first target distribution per unit for each quarter of our existence; less

(2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the first target distribution per unit that we distributed 85% to the unitholders, pro rata, and 15% to the holders of our incentive distribution rights for each quarter of our existence;

• sixth, 75% to all unitholders, pro rata, and 25% to the holders of our incentive distribution rights, until we allocate under this paragraph an amount per unit equal to:

(1) the sum of the excess of the third target distribution per unit over the second target distribution per unit for each quarter of our existence; less

(2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the second target distribution per unit that we distributed 75% to the unitholders, pro rata, and 25% to the holders of our incentive distribution rights for each quarter of our existence; and

• thereafter, 50% to all unitholders, pro rata, and 50% to the holders of our incentive distribution rights.

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The percentages set forth above are based on the assumption that our general partner has not transferred its incentive distribution rights and that we do not issue additional classes of equity securities.

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 fourth bullet point above will no longer be applicable.

Manner of Adjustments for Losses

If our liquidation occurs before the end of the subordination period, after making allocations of loss to the general partner and the unitholders in a manner intended to offset in reverse order the allocations of gains that have previously been allocated, we will generally allocate any loss to the holders of our incentive distribution rights and unitholders in the following manner:

• first, 100% to the holders of subordinated units in proportion to the positive balances in their capital accounts, until the capital accounts of the subordinated unitholders have been reduced to zero;

• second, 100% to the holders of common units in proportion to the positive balances in their capital accounts, until the capital accounts of the common unitholders have been reduced to zero; and

• thereafter, 100% to the holders of our incentive distribution rights.

The percentages set forth above are based on the assumption that our general partner has not transferred its incentive distribution rights and that we do not issue additional classes of equity securities.

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.

Adjustments to Capital Accounts

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 tax purposes, unrecognized gain resulting from the adjustments to the unitholders and the holder 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 holder of our incentive distribution rights based on their relative 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 units 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.

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SELECTED HISTORICAL AND PRO FORMA FINANCIAL DATA

The following table presents selected historical financial data of our Predecessor and selected unaudited pro forma financial data for Noble Midstream for the periods and as of the dates indicated. The following selected historical financial data of our Predecessor consists of all of the assets and operations of our Predecessor on a 100% basis. In connection with the completion of this offering, Noble will contribute to us the percentages of the assets described under “Certain Relationships and Related Party Transactions—Agreements with our Affiliates in Connection with the Transactions—Contribution Agreement.” However, as required by GAAP, we will continue to consolidate 100% of the assets and operations of our development companies in our financial statements.

The selected historical financial data of our Predecessor as of and for the years ended December 31, 2014 and 2013 and as of March 31, 2015 and for the three months ended March 31, 2015 and 2014 are derived from the audited and unaudited financial statements of our 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 audited and unaudited interim and pro forma 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.”

For the years ended December 2014 and 2013, our assets were part of the integrated operations of Noble, and our Predecessor generally recognized only the costs, and not the revenues, associated with certain of the midstream services provided to Noble on an intercompany basis. Accordingly, the midstream revenues in our Predecessor’s historical combined financial statements relate only to amounts received from third parties for those services and amounts received from Noble with respect to transactions for which there were contracts. For this reason, as well as other factors described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Factors Affecting the Comparability of Our Financial Results,” our future results of operations will not be comparable to our Predecessor’s historical results.

The selected unaudited pro forma financial data presented in the following table for the year ended December 31, 2014 and as of and for the three months ended March 31, 2015 are 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, 2015, and the unaudited pro forma condensed statements of operations for the year ended December 31, 2014 and the three months ended March 31, 2015 assume the offering and the related transactions occurred as of January 1, 2014. These transactions include, and the unaudited pro forma condensed financial statements give effect to, the following:

• Noble’s contribution to us of the percentages of the development companies that will operate our assets as described under “Certain Relationships and Related Party Transactions—Agreements with our Affiliates in Connection with the Transactions—Contribution Agreement;”

• our entry into long-term, fixed-fee commercial agreements with Noble;

• our entry into a new $         million revolving credit facility;

• our entry into an omnibus agreement with Noble;

• the consummation of this offering and our issuance of (i)             common units to the public, (ii) a non-economic general partner interest to our general partner and (iii)              common units,             subordinated units and the incentive distribution rights to Noble; and

• the application of the net proceeds of this offering as described in “Use of Proceeds.”

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The unaudited pro forma condensed financial statements do not give effect to (i) an estimated $         million in incremental general and administrative expenses that we expect to incur annually as a result of being a publicly traded partnership or (ii) variable general and administrative costs we will incur under the omnibus agreement and operational services agreement that we will enter into with Noble as of the closing of this offering.

	Noble Midstream Partners LP Predecessor Historical												Noble Midstream Partners LP Pro Forma
	Year Ended December 31,						Three Months Ended March 31,						Year Ended December 31, 2014	Three  Months Ended March 31, 2015
	2014			2013			2015			2014
							(unaudited)						(unaudited)
	(in thousands, except per unit data)
Statement of Operations Data
Revenues
Midstream Services—Related Party	$	2,086		$	2,169		$	12,852		$	513		$	$
Income from Investments		3,798			3,024			1,236			773
Total Revenues		5,884			5,193			14,088			1,286
Costs and Expenses
Direct Operating		8,538			2,760			2,670			2,318
Depreciation, Depletion and Amortization		11,315			3,092			1,345			2,250
General and Administrative		6,734			6,124			545			1,596
Total Operating Expense		26,587			11,976			4,560			6,164
Operating Income (Loss)		(20,703	)		(6,783	)		9,528			(4,878	)
Other Expense
Interest Expense, Net of Amount Capitalized		3,566			3,263			515			472
Total Other Expense		3,566			3,263			515			472
Income (Loss) Before Income Taxes		(24,269	)		(10,046	)		9,013			(5,350	)
Income Tax Provision (Benefit)		(9,178	)		(3,746	)		3,409			(2,023	)
Net Income (Loss) including non-controlling interests	$	(15,091	)	$	(6,300	)	$	5,604		$	(3,327	)	$	$
Net income attributable to non-controlling interests(1)
Net income attributable to Noble Midstream Partners LP
Net income per limited partner unit (basic and diluted):
Common units
Subordinated units
Balance Sheet Data (at period end):
Total Property, Plant and Equipment, Net	$	195,513		$	127,504		$	220,361					$	$
Total Assets		216,512			139,883			258,363
Net Parent Investment/partners’ capital		213,673			137,179			235,812
Statement of Cash Flows Data
Net Cash Provided by (Used in) Operating Activities	$	(12,534	)	$	(6,935	)	$	8,292		$	(2,994	)	$	$
Net Cash Used in Investing Activities		(79,904	)		(95,586	)		(19,884	)		(15,588	)
Net Cash Provided by Financing Activities		92,438			102,521			21,522			18,582
Other Data
Capital expenditures(2)	$	80,466		$	96,318		$	19,371		$	15,702		$	$
EBITDA(3)		(9,388	)		(3,691	)		10,873			(2,628	)
EBITDA attributable to Noble Midstream Partners LP(3)

(1) Represents     %,     %,     %,     % and     % non-controlling interests in the development companies that hold our operating assets that have been retained by Noble as described under “Certain Relationships and Related Party Transactions—Agreements with our Affiliates in Connection with the Transactions—Contribution Agreement.”

(2) Represents additions to property, plant and equipment within the combined statement of cash flows.

(3) For our definition of the non-GAAP financial measure of EBITDA and a reconciliation of EBITDA to our most directly comparable financial measures calculated and presented in accordance with GAAP, please read “—Non-GAAP Financial Measure.”

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Non-GAAP Financial Measure

We define EBITDA as net income (loss) before income taxes, net interest expense, depreciation, depletion and amortization. EBITDA is used as a supplemental financial measure by management and by external users of our financial statements, such as investors, industry analysts, lenders and ratings agencies, to assess:

• our operating performance as compared to those of other companies in the midstream energy industry, without regard to financing methods, historical cost basis or capital structure;

• the ability of our assets to generate sufficient cash flow to make distributions to our partners;

• our ability to incur and service debt and fund capital expenditures; and

• the viability of acquisitions and other capital expenditure projects and the returns on investment of various investment opportunities.

We believe that the presentation of EBITDA in this prospectus provides information useful to investors in assessing our financial condition and results of operations. The GAAP measures most directly comparable to EBITDA are net income and net cash provided by operating activities. EBITDA should not be considered an alternative to net income, net cash provided by (used in) operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. EBITDA excludes some, but not all, items that affect net income or net cash, and these measures may vary from those of other companies. As a result, EBITDA as presented below may not be comparable to similarly titled measures of other companies.

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The following table presents a reconciliation of EBITDA to net income and net cash provided by (used in) operating activities, the most directly comparable GAAP financial measures, on a historical basis and pro forma basis, as applicable, for each of the periods indicated.

	Noble Midstream Partners LP Predecessor Historical												Noble Midstream Partners LP Pro Forma
	Year Ended December 31,						Three Months Ended March 31,						Year Ended December  31, 2014		Three  Months Ended March 31, 2015
	2014			2013			2015			2014
							(unaudited)						(unaudited)
	(in thousands, except per unit data)
Reconciliation of EBITDA to Net Income (Loss) and to Net Cash Provided by (Used in) Operating Activities:
Net income (loss)	$	(15,091	)	$	(6,300	)	$	5,604		$	(3,327	)	$		$
Income tax (benefit) provision		(9,178	)		(3,746	)		3,409			(2,023	)
Interest expense, net of amount capitalized		3,566			3,263			515			472
Depreciation, depletion and amortization		11,315			3,092			1,345			2,250
EBITDA	$	(9,388	)		(3,691	)		10,873			(2,628	)
Changes in operating assets and liabilities		—			—			(2,123	)		—
Interest expense, net of amount capitalized		(3,566	)		(3,263	)		(515	)		(472	)
Stock based compensation and other		420			19			57			106
Net Cash Provided by (Used in) Operating Activities	$	(12,534	)	$	(6,935	)	$	8,292		$	(2,994	)
Reconciliation of EBITDA Attributable to Noble Midstream Partners LP to Net Income Attributable to Noble Midstream Partners LP:
Net income attributable to Noble Midstream Partners LP													$		$
Income tax (benefit) provision
Interest expense
Depreciation
EBITDA attributable to Noble Midstream Partners LP													$		$
Reconciliation of EBITDA Attributable to Non-controlling Interests to Net Income Attributable to Non-controlling Interests:
Net income attributable to non-controlling interests														$	$
Income tax (benefit) provision
Interest expense
Depreciation
EBITDA attributable to non-controlling interests													$		$

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

You should read the following discussion of the financial condition and results of operations of the predecessor of Noble Midstream Partners LP, or our Predecessor, in conjunction with the historical combined financial statements and unaudited condensed combined interim financial statements and notes of our Predecessor and the unaudited pro forma condensed financial statements for Noble Midstream Partners LP included elsewhere in this prospectus. Among other things, those historical, unaudited interim and unaudited pro forma financial statements include more detailed information regarding the basis of presentation for the following information. This discussion contains forward-looking statements that involve risks and uncertainties. Our actual results could differ materially from those discussed below. Factors that could cause or contribute to such differences include, but are not limited to, those identified below and those discussed in the sections entitled “Risk Factors” and “Forward-Looking Statements” included elsewhere in this prospectus.

Overview

We are a growth-oriented Delaware master limited partnership recently formed by our sponsor, Noble Energy, Inc., to own, operate, develop and acquire a wide range of domestic midstream infrastructure assets. We currently provide crude oil, natural gas, and water-related midstream services for Noble through long-term, fixed-fee contracts. Our operating assets are currently focused in the DJ Basin in Colorado, one of the premier liquid hydrocarbon basins in the United States. Noble intends for us to become its primary vehicle for domestic midstream operations that have not previously been dedicated to other ventures. We believe that our diverse midstream infrastructure assets and our relationship with Noble position us as a leading midstream service provider.

How We Generate Revenue

Our results are primarily driven by the volumes of crude oil that we gather and treat, natural gas that we gather, fresh water that we deliver and saltwater that we collect, clean and recycle or dispose of, and the fees we charge per unit of throughput for our midstream services.

Our crude oil infrastructure assets consist of gathering pipelines and treating facilities, which collectively prepare crude oil for sale. Our natural gas gathering system that services the production from the Wells Ranch IDP collects wet gas from separator facilities located at or near the wellhead and delivers the wet gas to the Wells Ranch CGF or other delivery points within the IDP areas. At the tailgate of our natural gas gathering facilities or the Wells Ranch CGF, as applicable, we deliver the natural gas for further gathering and processing by third parties. Our saltwater gathering systems gather and process liquids produced from operations in the DJ Basin and consist of a combination of separation and storage facilities, and permanent pipelines, as well as pumping stations to transport saltwater to disposal or recycling facilities. Our fresh water system provides services for both recycled and treated saltwater and raw fresh water, for example, that has been withdrawn from a river or ground water.

We have entered into multiple fee-based commercial agreements with Noble, each with an initial term of 15 years, utilizing our infrastructure assets to provide an array of essential services critical to Noble’s upstream operations. Our agreements include substantial acreage dedications. See “Business—Our Acreage Dedication.”

Our investment in White Cliffs LLC is accounted for under the cost method of investment as we have virtually no influence over partnership operations and financial policies. On a monthly basis, White Cliffs LLC makes cash distributions to its members, including us. Under the cost method of accounting, we recognize these distributions as earnings to the extent there is net income, and record distributions in excess of our ratable share of earnings as return of investment.

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We have indirect exposure to commodity price risk in that persistent low commodity prices may cause Noble or other potential customers to delay drilling or shut in production, which would reduce the volumes available for gathering and processing by our infrastructure assets. If Noble delays drilling or temporarily shuts in production due to persistently low commodity prices or for any other reason, we are not assured a certain amount of revenue as our commercial agreements with Noble do not contain minimum volume commitments. Please read “Risk Factors—Risks Related to Our Business—Because of the natural decline in production from existing wells, our success, in part, depends on our ability to maintain or increase hydrocarbon throughput volumes on our midstream systems, which depends on Noble’s levels of development and completion activity on our dedicated acreage.”

Under each of our commercial agreements, the fees we charge Noble are automatically increased each calendar year by a percentage calculated based on the change in the consumer price index. In addition, each year we will propose a redetermination of the fees charged under our various systems on an annual basis, taking into account, among other things, expected capital expenditures necessary to provide our services under the applicable development plan. However, if we and Noble are unable to agree on a fee redetermination (other than the automatic annual adjustment), the prior fee will remain in effect.

How We Evaluate Our Operations

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

Throughput Volumes

The amount of revenue we generate primarily depends on the volumes of crude oil, natural gas and water for which we provide midstream services. These volumes are affected primarily by changes in the supply of and demand for crude oil, natural gas and NGLs in the markets served directly or indirectly by our assets, such as the recent decline in commodity prices beginning in the fourth quarter of 2014. Noble’s willingness to engage in new drilling is determined by a number of factors, the most important of which are the prevailing and projected prices of crude oil, natural gas, the cost to drill and operate a well, expected well performance, the availability and cost of capital and environmental and government regulations. We generally expect the level of drilling to positively correlate with long-term trends in commodity prices. Similarly, production levels nationally and regionally generally tend to positively correlate with drilling activity.

In order to meet our contractual obligations under our commercial agreements with Noble in respect of new wells drilled on our dedicated acreage, we will be required to incur capital expenditures to extend our infrastructure assets and facilities to the new wells drilled. We estimate that total expansion capital expenditures for the twelve months ending September 30, 2016 will be $         million ($         million net to our ownership interests in our development companies, which we expect to fund with borrowings under our new revolving credit facility). Noble will be responsible for its proportionate share of the total capital expenditures associated with the ongoing build-out of the midstream systems owned by our development companies. See “Cash Distribution Policy and Restrictions on Distributions—Significant Forecast Assumptions—Capital Expenditures.”

Noble has dedicated acreage to us based on the services we provide. As of January 1, 2015, Noble has dedicated to us, for a period of 15 years, subject to existing dedications or rights of first refusal, approximately 300,000 net acres in the Wells Ranch IDP, East Pony IDP, Mustang IDP, Greeley Crescent IDP and Bronco IDP. Our commercial agreements with Noble provide that, in addition to our existing dedicated acreage, any future acreage that is acquired by Noble in these IDP areas, and that is not subject to a pre-existing third-party

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commitment, will be included in the dedication to us for midstream services, including gathering, processing and treating. Based on Noble’s dedication to us and previously granted dedications, we anticipate providing crude oil and water-related midstream services on any wells that Noble elects to drill in the Wells Ranch IDP, East Pony IDP, Mustang IDP, Greeley Crescent IDP and Bronco IDP, as well as certain natural gas gathering services on any wells drilled in the Wells Ranch IDP and Mustang IDP. The number of wells Noble may drill, and timing with respect to these wells, will depend on numerous factors (some of which are beyond their control and all of which are beyond our control), including commodity prices, weather, government regulation, geologic interpretation and the economic environment.

Because the production rate of a well declines over time, we must continually obtain new supplies of crude oil, natural gas and saltwater to maintain or increase the throughput volumes on our midstream systems. Our ability to maintain or increase existing throughput volumes and obtain new supplies of crude oil, natural gas and saltwater are impacted by:

• successful drilling activity by Noble on our dedicated acreage and our ability to fund the capital costs required to connect our infrastructure assets to new wells;

• our ability to utilize the remaining uncommitted capacity on, or add additional capacity to, our infrastructure assets;

• the level of work-overs and re-completions of wells on existing pad sites to which our infrastructure assets are connected;

• our ability to increase throughput volumes on our infrastructure assets by making outlet connections to existing or new third-party pipelines or other facilities, primarily driven by the anticipated supply of and demand for crude oil, natural gas and water;

• our ability to identify and execute organic expansion projects to capture incremental volumes from Noble and third parties;

• our ability to compete for volumes from successful new wells in the areas in which we operate outside of our dedicated acreage; and

• our ability to gather natural gas, gather and treat crude oil and provide water services with respect to hydrocarbons produced on acreage that has been released from commitments with our competitors.

We actively monitor producer activity in the areas served by our infrastructure assets to pursue new supply opportunities.

EBITDA

We define EBITDA as net income (loss) before income taxes, net interest expense, depreciation and amortization. EBITDA is used as a supplemental financial measure by management and by external users of our financial statements, such as investors, industry analysts, lenders and ratings agencies, to assess:

• our operating performance as compared to those of other companies in the midstream energy industry, without regard to financing methods, historical cost basis or capital structure;

• the ability of our assets to generate sufficient cash flow to make distributions to our partners;

• our ability to incur and service debt and fund capital expenditures; and

• the viability of acquisitions and other capital expenditure projects and the returns on investment of various investment opportunities.

We believe that the presentation of EBITDA in this prospectus provides information useful to investors in assessing our financial condition and results of operations. The GAAP measures most directly comparable to EBITDA are net income and net cash provided by operating activities. EBITDA should not be considered an

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alternative to net income, net cash provided by (used in) operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. EBITDA excludes some, but not all, items that affect net income or net cash, and these measures may vary from those of other companies. As a result, our EBITDA may not be comparable to similarly titled measures of other companies.

For a discussion of the non-GAAP financial measure of EBITDA and a reconciliation of EBITDA to its most comparable measures calculated and presented in accordance with GAAP, please read “Selected Historical and Pro Forma Financial Data—Non-GAAP Financial Measure.”

Distributable Cash Flow

Although we have not quantified distributable cash flow on a historical basis, after the completion of this offering, we intend to use distributable cash flow, which we define as EBITDA less net cash interest paid and estimated maintenance capital expenditures, to analyze our performance. Distributable cash flow will not reflect changes in working capital balances.

We believe that the presentation of distributable cash flow in this prospectus provides information useful to investors in assessing our financial condition and results of operations. The GAAP measures most directly comparable to distributable cash flow are net income and net cash provided by operating activities. Distributable cash flow should not be considered an alternative to net income, net cash provided by operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Distributable cash flow excludes some, but not all, items that affect net income or net cash provided by operating activities, and these measures may vary from those of other companies. As a result, our distributable cash flow may not be comparable to similarly titled measures of other companies.

Operating Expense; General and Administrative Expense

Operating Expense

We seek to maximize the profitability of our operations in part by minimizing, to the extent appropriate, expenses directly tied to operating our assets. Direct labor costs, ad valorem taxes, repair and non-capitalized maintenance costs, integrity management costs, utilities and contract services comprise the most significant portion of our operations and maintenance expense. These expenses generally remain relatively stable across broad ranges of throughput volumes but can fluctuate from period to period depending on the mix of activities performed during that period and the timing of these expenses. We will seek to manage our operating expenditures on our midstream systems by scheduling maintenance over time to avoid significant variability in our maintenance expenditures and minimize their impact on our cash flow.

General and Administrative Expense

Our Predecessor’s general and administrative expense included an allocation of charges for the management and operation of our assets by Noble for general and administrative services, such as information technology, treasury, accounting, human resources and legal services and other financial and administrative services. Following the completion of this offering, Noble will charge us a combination of direct and allocated charges for general and administrative services.

We anticipate incurring approximately $             million of incremental general and administrative expenses attributable to being a publicly traded partnership, which includes expenses associated with annual, quarterly and current reporting with the SEC; tax return and Schedule K-1 preparation and distribution; Sarbanes-Oxley compliance; listing on the NYSE; independent auditor fees; legal fees; investor relations expenses; transfer agent and registrar fees; incremental salary and benefits costs; outside director fees; and insurance expenses. These incremental general and administrative expenses are not reflected in our historical or our pro forma financial statements. Our future general and administrative expense will also include compensation expense associated with the Noble Midstream Partners LP 2015 Long-Term Incentive Plan.

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Factors Affecting the Comparability of Our Financial Results

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

Ownership of Our Assets

Our Predecessor’s historical results of operations include all of the results of operations of Noble’s midstream business in the DJ Basin on a 100% basis, which includes distributions in respect of our membership interest in White Cliffs LLC, 100% of the results of our Core Assets and Growth Assets, as well as 100% of the results of certain ancillary midstream assets that Noble will retain after the completion of this offering. In connection with the completion of this offering, Noble will contribute to us a     % controlling interest in the development company that owns our Core Assets, except for our 3.33% ownership interest in White Cliffs LLC, and operating interests ranging from     % to     % in our Growth Assets. Consequently, our results of operations after the completion of this offering will reflect less than 100% of the results of our Core Assets and Growth Assets.

Revenues

There are differences between the sources of our Predecessor’s revenues prior to January 1, 2015 and the sources of our Predecessor’s revenues beginning January 1, 2015. The revenues in our Predecessor’s historical combined financial statements for the year ended December 31, 2013 and December 31, 2014 relate to the crude oil treating facilities and distributions received from White Cliffs LLC. Our remaining infrastructure assets were part of the integrated operations of Noble for which documented intercompany arrangements did not exist. Effective January 1, 2015, we generate revenues under fee-based arrangements with Noble. Following the closing of this offering, we will earn revenues under our long-term commercial agreements with Noble and will receive separate fixed fees for the midstream services that we provide.

Depreciation Expense

As of January 1, 2015 depreciation related to our assets placed in service is calculated using the straight-line method. Historically, Noble has operated midstream assets in support of its U.S. onshore upstream business as a cost center within the United States reportable segment. Due to the change in the intended use of these assets, Noble changed the method of depreciation from units-of-production to the preferable straight-line method for future accounting periods. Depreciation will be calculated on a straight-line basis from the first quarter of 2015, the period of change, and in prospective periods, with no cumulative adjustment for prior periods.

General and Administrative Expenses

Our Predecessor’s general and administrative expenses included an allocation for the management and operation of our assets by Noble for general corporate services, such as treasury, accounting, human resources and legal services. These expenses were charged or allocated to our Predecessor based on the nature of the expenses and our Predecessor’s direct usage when identifiable or capital expenditures. Following the closing of this offering, we will pay Noble an annual secondment fee under our employee secondment agreement for the costs of certain employees seconded to our general partner in support of our operations, and Noble will charge us fees under our omnibus agreement for certain general and administrative services, such as treasury, accounting and legal services, that Noble will continue to provide to us. These fees will be based on an allocation of the costs associated with providing these services to us. For more information about the fees we will pay to Noble under our employee secondment and omnibus agreements and the services covered by those fees, please read “Certain Relationships and Related Party Transactions—Agreements with our Affiliates in Connection with the Transactions.” We also expect to incur an additional $         million of incremental annual general and administrative expenses as a result of being a separate publicly traded partnership that are not reflected in our Predecessor’s historical combined financial statements.

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Financing

There are differences in the way we will finance our operations as compared to the way our Predecessor historically financed operations. Historically, our Predecessor’s operations were financed as part of Noble’s integrated operations and, other than interest under our Predecessor’s affiliate loan facilities with Noble, Noble allocated interest expense to our Predecessor for financing its operations.

Our partnership agreement requires that we distribute all of our available cash to our unitholders. As a result, we expect to rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. Following the completion of this offering, we intend to have no debt and an available borrowing capacity of $         million under a new revolving credit facility.

Income Taxes

Our Predecessor was part of the integrated operations of Noble. As such, our Predecessor was part of Noble’s consolidated corporate tax return in all state and federal tax jurisdictions in which Noble and our Predecessor had operations. 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. Income taxes have been calculated on a separate return basis as if the Predecessor were a stand-alone entity. Unlike the Partnership, however, the Predecessor is included in the Noble U.S. consolidated federal income tax return and U.S. state income tax returns on a combined basis with Noble, as required.

Other Factors Impacting Our Business

We expect our business to continue to be affected by the following key factors. Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about, or interpretations of, available information prove to be incorrect, our actual results may vary materially from our expected results.

Supply and Demand for Crude Oil and Natural Gas

We currently generate all of our revenues under fee-based agreements with Noble. We expect these contracts to promote cash flow stability and minimize our direct exposure to commodity price fluctuations, since we generally do not own any of the crude oil, natural gas, or water that we handle and do not engage in the trading of crude oil or natural gas. However, commodity price fluctuations indirectly influence our activities and results of operations over the long term, since they can affect production rates and investments by Noble and third parties in the development of new crude oil and natural gas reserves. As a result of the decline in commodity prices beginning in the fourth quarter of 2014, Noble announced that it plans to reduce its rig count as part of its 2015 capital program. However, mechanisms under our commercial agreements minimize our exposure to this planned reduction. In particular, the fee recalculation mechanisms under the agreements allow fees to be adjusted annually to provide cash flow stability. Generally, drilling and production activity will increase as crude oil and natural gas prices increase. The throughput volumes at our assets depend primarily on the volumes of crude oil and natural gas produced by Noble in the DJ Basin, which, in turn, is ultimately dependent on Noble’s margins. Noble’s margins depend on many factors, including the price of crude oil and natural gas and operational costs. These prices are volatile and influenced by numerous factors beyond our or Noble’s control, including the domestic and global supply of and demand for crude oil and natural gas. The commodities trading markets, as well as other supply and demand factors, may also influence the selling prices of crude oil and natural gas. Furthermore, our ability to execute our growth strategy in the DJ Basin will depend on crude oil and natural gas production in that area, which is also affected by the supply of and demand for crude oil and natural gas.

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Regulatory Compliance

The regulation of crude oil and natural gas gathering and transportation and water services activities by federal and state regulatory agencies has a significant impact on our business. See “Business—Regulation of Operations.” Our operations are also impacted by new regulations, which have increased the time that it takes to obtain required permits.

Additionally, increased regulation of crude oil and natural gas producers in our areas of operation, including regulation associated with hydraulic fracturing, could reduce regional supply of crude oil, natural gas and water and therefore throughput on our infrastructure assets. For more information see “Business—Regulation of Operations.”

Results of Operations

Three Months Ended March 31, 2015 Compared to the Three Months Ended March 31, 2014

	Three Months Ended March 31,					Increase (Decrease) from Prior Year
	2015		2014
($ in thousands)
Revenues
Midstream Services—Related Party	$	12,852	$	513			2,405	%
Income from Investments		1,236		773			60	%
Total Revenues		14,088		1,286			995	%
Costs and Expenses
Direct Operating		2,670		2,318			15	%
Depreciation, Depletion and Amortization		1,345		2,250			(40	)%
General and Administrative		545		1,596			(66	)%
Total Operating Expenses		4,560		6,164			(26	)%
Operating Income (Loss)		9,528		(4,878	)
Other Expense
Interest, Net of Amount Capitalized		515		472			9	%
Total Other Expense		515		472			9	%
Income (Loss) Before Income Taxes		9,013		(5,350	)
Income Tax Provision (Benefit)		3,409		(2,023	)
Net Income (Loss)	$	5,604	$	(3,327	)

Revenue. Revenue from midstream operations was approximately $12.9 million for the three months ended March 31, 2015 as compared to $0.5 million for the three months ended March 31, 2014. Effective January 1, 2015, we entered into multiple commercial agreements with Noble, for which we receive a volumetric fee for the midstream services we provide. Revenues for the three months ended March 31, 2014 were solely from our crude oil treating facilities. Our remaining midstream infrastructure was part of the integrated operations of Noble and documented intercompany arrangements did not exist prior to January 1, 2015. The increase was primarily due to $2.8 million related to crude oil gathering, $0.5 million related to crude oil treating, $4.2 million related to natural gas gathering, $3.1 million related to fresh water services, $1.8 million due to saltwater services.

Income from Investments. Our investment in White Cliffs LLC is accounted for under the cost method of investment as we have virtually no influence over partnership operations and financial policies. The increase in income from investments is primarily due to an increase in the distributions from White Cliffs LLC for the three months ended March 31, 2015 as compared with the three months ended March 31, 2014.

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Direct Operating Expense. Operating expense is comprised of direct labor costs, ad valorem and property taxes, repair and non-capitalized maintenance costs, utilities and contract services. These expenses generally remain relatively stable across broad ranges of throughput volumes but can fluctuate from period to period depending on the mix of activities performed during that period and the timing of these expenses. Total direct operating expense was approximately $2.7 million for the three months ended March 31, 2015 compared to $2.3 million for the three months ended March 31, 2014. The $0.4 million increase in operating expense was primarily related to crude oil gathering, crude oil treating and natural gas gathering due to increased usage of our infrastructure and facilities.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense decreased $1.0 million to $1.3 million for the three months ended March 31, 2015 compared to $2.3 million for the three months ended March 31, 2014. Beginning in January 2015, Noble elected to begin operating the midstream business as if it were a stand-alone business. Historically, Noble has operated the midstream assets in support of the U.S. onshore upstream business as a cost center within the United States reportable segment. Due to the change in the intended use of these assets, Noble changed the method of depreciation from units-of-production to the preferable straight-line method for future accounting periods. Depreciation will be calculated on a straight-line basis from the first quarter of 2015, the period of change, and in future periods. Following this adjustment, our assets will have useful lives ranging from 24 to 30 years. For assets that were converted from the unit-of-production method, their respective asset lives will be 30 years from the date originally placed into service.

General and Administrative Expense. General and administrative expense is primarily comprised of an allocation of monthly charges for the management and operation of our assets by Noble including general corporate services, such as information technology, treasury, accounting, human resources, legal services and other financial and administrative services. These expenses were charged or allocated to us based on the nature of the expenses and our Predecessor’s direct usage when identifiable or capital expenditures. Total general and administrative expense was $0.5 million for the three months ended March 31, 2015 compared to $1.6 million for the three months ended March 31, 2014. The decrease was primarily due to our entry into a fixed overhead services agreement with Noble. Prior to this agreement, our general and administrative expenses were primarily driven by an allocation from Noble’s integrated and consolidated operations.

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Year Ended December 31, 2014 Compared to the Year Ended December 31, 2013

	Year Ended December 31,						Increase (Decrease) from Prior Year
	2014			2013
($ in thousands)
Revenues
Midstream Services—Related Party	$	2,086		$	2,169			(4	)%
Income from Investments	$	3,798		$	3,024			26	%
Total Revenues		5,884			5,193			13	%
Costs and Expenses
Direct Operating		8,538			2,760			209	%
Depreciation, Depletion and Amortization		11,315			3,092			266	%
General and Administrative		6,734			6,124			10	%
Total Operating Expenses		26,587			11,976			122	%
Operating Loss		(20,703	)		(6,783	)
Other Expense
Interest, Net of Amount Capitalized		3,566			3,263			9	%
Total Other Expense		3,566			3,263			9	%
Loss Before Income Taxes		(24,269	)		(10,046	)
Income Tax Benefit		(9,178	)		(3,746	)
Net Loss and Comprehensive Loss	$	(15,091	)	$	(6,300	)

Revenue. Revenue from midstream operations was approximately $2.1 million in 2014 compared to approximately $2.2 million in 2013. Revenues in 2014 and 2013 were solely from our crude oil treating facilities. Our remaining midstream infrastructure was part of the integrated operations of Noble and documented intercompany arrangements did not exist.

Income from Investments. Our investment in White Cliffs LLC is accounted for under the cost method of investment as we have virtually no influence over partnership operations and financial policies. The increase in income from investments is primarily due to an increase in the distributions from White Cliffs LLC in 2014 as compared to 2013.

Direct Operating Expense. Operating expense is comprised of direct labor costs, ad valorem and property taxes, repair and non-capitalized maintenance costs, integrity management costs, utilities and contract services. These expenses generally remain relatively stable across broad ranges of throughput volumes but can fluctuate from period to period depending on the mix of activities performed during that period and the timing of these expenses. Total direct operating expense was approximately $8.5 million in 2014 compared to $2.8 million in 2013. The $5.7 million increase in operating expense was primarily related to a full year of operation at the Wells Ranch CGF, expanded operations at our second crude oil treating facility and increased utilization of the Wells Ranch gathering system.

General and Administrative Expense. General and administrative expense is primarily comprised of allocated monthly charges for the management and operation of our assets and certain expenses by Noble including general corporate services, such as information technology, treasury, accounting, human resources, legal services and other financial and administrative services. These expenses were charged or allocated to us based on the nature of the expenses and our Predecessor’s direct usage when identifiable or capital expenditures. Total general and administrative expense was $6.7 million in 2014 compared to $6.1 million in 2013. The increase was primarily due to increase in personnel and activity to support the significant expansion of infrastructure assets and midstream services provided to Noble.

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Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense increased by $8.2 million to $11.3 million in 2014 compared to $3.1 million in 2013. The increase was primarily related to a full year of activity at the Wells Ranch CGF and our second crude oil treating facility, both of which were placed into service in the second half of 2013. Additionally, depreciation expense increased in 2014 compared to 2013 due to expansion of our fresh water systems in both the Wells Ranch IDP and the East Pony IDP.

Capital Resources and Liquidity

Liquidity and Financing Arrangements

Historically, our sources of liquidity were based on cash flow from operations and funding from Noble. During the year ended December 31, 2014, we participated in Noble’s centralized cash management system. As a result, our Predecessor’s historical financial statements do not include cash or cash equivalents since cash receipts from all our Predecessor’s operations were deposited into Noble’s bank accounts and all cash disbursements were made from these accounts. In connection with this offering, we will establish our own cash management system that will be administered by Noble on our general partner’s behalf under our omnibus agreement.

We do not have any commitment from Noble or our general partner or any of their respective affiliates to fund our cash flow deficits or provide other direct or indirect financial assistance to us following the closing of this offering. 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 requirements and long-term capital expenditure requirements and to make quarterly cash distributions.

Our partnership agreement requires that we distribute all of our available cash to our unitholders. As a result, we expect to rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures.

We intend to pay a minimum quarterly distribution of $         per unit per quarter, 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. 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 “Cash Distribution Policy and Restrictions on Distributions.”

Revolving Credit Facility

Prior to or in connection with the completion of this offering, we intend to enter into a new $         million revolving credit facility. Our new revolving credit facility will be available to fund working capital and to finance acquisitions and other capital expenditures. Borrowings under our revolving credit facility are expected to bear interest at LIBOR plus an applicable spread. LIBOR and the applicable spread will be defined in the credit agreement that evidences our new revolving credit facility. We expect the unused portion of the revolving credit facility will be subject to a commitment fee.

We expect our revolving credit facility to contain covenants and conditions that, among other things, limit our ability to incur or guarantee additional debt, make cash distributions, incur certain liens or permit them to exist, make certain investments and acquisitions, enter into certain types of transactions with affiliates, merge or consolidate with another company, and transfer, sell or otherwise dispose of assets. We also expect to be subject to covenants that require us to maintain certain financial ratios.

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Cash Flows

Net cash provided by operating activities, investing activities and financing activities for the years ended December 31, 2014 and 2013, and the three months ended March 31, 2015 and 2014 were as follows:

	Years Ended December 31,						Three Months Ended March 31,
	2014			2013			2015			2014
($ in thousands)
Net cash provided by (used in) operating activities:	$	(12,534	)	$	(6,935	)	$	8,292		$	(2,994	)
Net cash used in investing activities:	$	(79,904	)	$	(95,586	)	$	(19,884	)	$	(15,588	)
Net cash provided by financing activities:	$	92,438		$	102,521		$	21,522		$	18,582

For the year ended December 31, 2014 as compared to the year ended December 31, 2013:

Net cash used in operating activities increased $5.6 million during the year ended December 31, 2014 compared to year ended December 31, 2013. The increase was primarily due to the $8.8 million increase in net loss and a $5.3 million increase in deferred tax benefits. This increase was offset, in part, by a $8.2 million increase in depreciation.

Cash used in investing activities decreased due to reduced capital expenditures related to the expansion of our midstream systems. Capital expenditures decreased in 2014 as compared to 2013 due to the completion of the Wells Ranch CGF in the second half of 2013. Our continued investment in midstream infrastructure is in support of Noble’ growing production on our dedicated acreage in the DJ Basin.

Cash provided by financing activities decreased due to a reduction of capital expansion investment by Noble.

For the three months ended March 31, 2015 as compared to the three months ended March 31, 2014:

Net cash provided by operating activities increased by $11.3 million during the three months ended March 31, 2015 compared to the same period in 2014. The increase was primarily due to an increase in net income due to our entry into commercial agreements in January of 2015. This increase was offset, in part, by an increase in accounts receivable.

Cash used in investing activities increased $4.3 million for the three months ended March 31, 2015 compared to the three months ended March 31, 2014. Capital spending increased due to the expansion of the Wells Ranch CGF and crude oil gathering infrastructure in East Pony.

Cash provided by financing activities increased due to additional investments in us by Noble.

Capital Expenditures

The midstream energy business is capital intensive, requiring the maintenance of existing gathering systems and other midstream assets and facilities and the acquisition or construction and development of new gathering systems and other midstream assets and facilities. Our partnership agreement will require that we categorize our capital expenditures as either:

• Maintenance capital expenditures, which are cash expenditures (including expenditures for the construction or development of new capital assets or the replacement, improvement or expansion of existing capital assets) made to maintain, over the long term, our 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

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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, our operating capacity, operating income or revenue; or

• Expansion capital expenditures, which are cash expenditures to acquire additional interests in our midstream assets and construct new midstream infrastructure and those expenditures incurred 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 throughput. Examples of expansion capital expenditures include the acquisition of additional interests in our midstream assets and the construction, development or acquisition of additional gathering pipelines central gathering facilities, in each case to the extent such capital expenditures are expected to expand our operating capacity, operating income or revenue. In the future, if we make acquisitions that increase system throughput or capacity, the associated capital expenditures may also be considered expansion capital expenditures.

For the year ended December 31, 2014, the total capital expenditures of our Predecessor were $79.2 million on a 100% basis, of which $65.0 million was related to gathering assets and $14.2 million was related to freshwater delivery assets. The gathering asset expenditures were primarily associated with the construction of the Wells Ranch CGF, Wells Ranch gathering system and East Pony crude oil gathering system. Historically, we did not make a distinction between maintenance and expansion capital expenditures. We have estimated, however, that approximately $         million of these capital expenditures were maintenance capital expenditures.

For the three months ended March 31, 2015, the total capital expenditures of our Predecessor were $26.2 million on a 100% basis, of which $22.4 million was related to gathering assets, and $3.8 million was related to freshwater delivery systems. The gathering asset expenditures were primarily associated with the construction of the East Pony crude oil gathering system and expansion of the Wells Ranch CGF. Historically, we did not make a distinction between maintenance and expansion capital expenditures. We have estimated, however, that approximately $         million of these capital expenditures were maintenance capital expenditures.

We estimate that total capital expenditures attributable to our development companies for the twelve months ending September 30, 2016 will be $         million ($         million net to our ownership interests in our development companies). We estimate that expansion capital expenditures for the twelve months ending September 30, 2016 will be $         million ($         million net to our ownership interests in our development companies), primarily relating to gathering pipeline expansions, including 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 development companies) for the twelve months ending September 30, 2016. Please read “Cash Distribution Policy and Restrictions on Distributions—Significant Forecast Assumptions—Capital Expenditures.”

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.

Off-Balance Sheet Arrangements

None.

Critical Accounting Polices

Critical accounting policies are those that are important to our financial condition and require management’s most difficult, subjective or complex judgments, and the amount of assets and liabilities as of the date of the

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combined financial statements. The revenue and expenses for a period could differ significantly due to changes in these judgments or assumptions. We have evaluated the accounting policies used in the preparation of the accompanying combined financial statements of our Predecessor and related notes thereto and believe those policies are reasonable and appropriate.

We apply those accounting policies that we believe best reflect the underlying business and economic events, consistent with GAAP. Our more critical accounting policies include those related to property and equipment and asset retirement obligations. Inherent in such policies are certain key assumptions and estimates. We periodically update the estimates used in the preparation of the financial statements based on our latest assessment of the current and projected business and general economic environment. Our significant accounting policies are summarized in Note 2 to the audited combined financial statements of our Predecessor appearing elsewhere in this prospectus. We believe the following to be our most critical accounting policies applied in the preparation of our Predecessor’s financial statements.

We are an “emerging growth company” pursuant to the Jumpstart Our Business Startups Act, or JOBS Act. The JOBS Act provides that an emerging growth company may delay adopting new or revised accounting standards until such time as those standards apply to private companies. We have elected not to take advantage of this exemption and, therefore, plan to adopt new or revised accounting standards at the time those standards apply to public companies.

Investments

We account for our investment in partnerships using either the cost method or the equity method. We use the equity method of accounting for investments when we have the ability to exercise significant influence. We define significant influence as the ability to participate as a member of a board of directors or management and/or participate in policy-making processes.

We use the cost method of accounting for investments when we have virtually no ability to influence financial and operating policies.

Property, Plant and Equipment

Property, plant and equipment is recorded at cost upon acquisition. Expenditures which extend the useful lives of existing property, plant and equipment are capitalized.

When properties are retired or otherwise disposed, the related cost and accumulated depreciation are removed from the respective accounts and any profit or loss on disposition is recognized as gain or loss. There were no retirements or disposals during the periods presented.

During the carve-out period, certain assets were accounted for under the successful efforts method of accounting within Noble’s integrated operations. Under this method, costs to acquire mineral interests in crude oil and natural gas properties, drill and equip exploratory wells that find proved reserves, and drill and equip development wells are capitalized. Capitalized costs of producing crude oil and natural gas properties, along with support equipment and facilities, are amortized to expense by the unit-of-production method based on proved crude oil, natural gas and NGL reserves on a field-by-field basis, as estimated by Noble’s qualified petroleum engineers. Noble’s policy is to use quarter-end reserves and add back current period production to compute quarterly depreciation, depletion and amortization expense. Costs of certain gathering facilities serving a number of properties are depreciated using the straight-line method over the useful lives of the assets ranging from three to thirty years. Upon sale or retirement of depreciable or depletable property, the cost and related accumulated depreciation, depletion and amortization is eliminated from the accounts and the resulting gain or loss is recognized. Repairs and maintenance are expensed as incurred.

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Depreciation, Depletion and Amortization

Depreciation, depletion and amortization expense totaled $11.3 million for the year ended December 2014, and $3.1 million for the year ended December 31, 2013. Depreciation, depletion and amortization expense of these assets totaled $1.3 million and $2.3 million for the three months ended March 31, 2015 and 2014, respectively. The determination of estimated useful lives is a significant element in arriving at the results of operations. If the useful lives of the assets were found to be shorter than originally estimated, depreciation, depletion and amortization charges would be accelerated. Additional information concerning long-lived assets and related depreciation, depletion and amortization appears in Note 4 of the combined audited financial statements of our Predecessor appearing elsewhere in this prospectus.

Asset Retirement Obligations

Our asset retirement obligations (ARO) consist of estimated costs of dismantlement, removal, site reclamation and similar activities associated with our infrastructure assets. We recognize the fair value of a liability for an ARO in the period in which it is incurred, when we have an existing legal obligation associated with the retirement of our infrastructure assets and the obligation can reasonably be estimated. The associated asset retirement cost is capitalized as part of the carrying cost of the infrastructure asset. The recognition of an ARO requires that management make numerous estimates, assumptions and judgments regarding such factors as: the existence of a legal obligation for an ARO; estimated probabilities, amounts and timing of settlements; the credit-adjusted risk-free rate to be used; and inflation rates. In periods subsequent to initial measurement of the ARO, we recognize period-to-period changes in the liability resulting from the passage of time and revisions to either the timing or the amount of the original estimate of undiscounted cash flows. Revisions also result in increases or decreases in the carrying cost of the asset. Increases in the ARO liability due to passage of time impact net income as accretion expense. The related capitalized cost, including revisions thereto, is charged to expense through depreciation, depletion and amortization. Asset retirement obligations totaled $2.8 million and $2.7 million at December 31, 2014 and 2013, respectively.

Contractual Obligations

The following table details the future projected payments associated with our contractual obligations as of December 31, 2014.

	Payments Due by Year
	2015		2016-2017		2018-2019		2020 and Thereafter		Total
($ in thousands)
Asset Retirement Obligations	$	—	$	—	$	—	$	4,833	$	4,833
Surface Lease Obligations (1)	$	52	$	104	$	104	$	613	$	873
Total	$	52	$	104	$	104	$	5,446	$	5,706

(1) Surface lease obligations represent annual payments to landowners under three surface leases.

Qualitative and Quantitative Disclosures About Market Risk

Commodity Price Risk

We currently generate most of our revenues pursuant to fee-based commercial agreements under which we are paid based on the volumes of crude oil, natural gas and water that we gather and handle, rather than the underlying value of the commodity. In addition, we have one tariff on file. Consequently, our existing operations and cash flows have little direct exposure to commodity price risk. Although we intend to enter into similar fee-based gathering agreements with new customers in the future, our efforts to negotiate such terms may not be successful.

We may acquire or develop additional midstream assets in a manner that increases our exposure to commodity price risk. Future exposure to the volatility of crude oil, natural gas and NGL prices could have a material adverse effect on our business, financial condition, results of operations, cash flows and ability to make cash distributions to our unitholders.

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Interest Rate Risk

In connection with the completion of this offering we expect to enter into a new revolving credit facility. Assuming our average debt level of $         million, comprised of funds drawn on our new revolving credit facility, an increase of one percentage point in the interest rates will result in an increase in annual interest expense of $         million. 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.

Seasonality

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. These seasonal anomalies can increase demand for crude oil and natural gas during the summer and winter months and decrease demand for crude oil and natural gas during the spring and fall months. With respect to 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 winter weather may also impact or slow the ability of Noble to execute its drilling and development plan.

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INDUSTRY OVERVIEW

General

We provide crude oil, natural gas, and water-related midstream services for Noble. The market we serve, which begins at the source of production and extends through the gathering, processing and treating of hydrocarbons delivering them to takeaway pipelines, is a major component of what is commonly referred to as the “midstream” market.

Crude Oil Midstream Industry

General

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, treating and storage of crude oil. The following diagram illustrates the various components of the midstream value chain:

Midstream Services

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 option for transporting crude oil from a producer’s perspective.

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Treating. Crude oil treating assets process crude oil to remove basic sediment and water contained in crude oil after production. Crude oil delivery points, including crude oil terminals, storage facilities, long-haul crude oil pipelines and refineries, often have specific requirements for the amount of sediment and water that can be contained in any crude oil delivered to them. If crude oil does not meet their requirements after being gathered, crude oil treating facilities reduce the sediment and water content to acceptable levels. Crude oil is delivered to treating facilities by truck, where the basic sediment and water content of the crude oil is analyzed to determine if a truckload requires treatment prior to delivery into downstream delivery points.

Natural Gas Midstream Industry

General

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, compressing, processing, treating, fractionating, transporting, storing or marketing natural gas and NGLs. Our natural gas midstream operations currently focus on the gathering of natural gas. The following diagram illustrates the various components of the midstream value chain:

Midstream Services

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

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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.

Water Services Industry

Fresh Water Distribution and Storage. Fresh water, 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 fresh water 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. Fresh water refers to water that has been recycled and 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) fresh water 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 fresh water distribution.

Saltwater Gathering and Transportation. Saltwater accounts for the largest waste stream volume associated with crude oil and natural gas production. Producers often seek to outsource saltwater handling and disposal to third parties in order to preserve capital and engineering time for drilling. Flowback from the hydraulic fracturing process creates additional water volumes that must be disposed of by producers. In the DJ Basin, wells with longer lateral lengths, increased hydraulic fracturing stages and downspacing of well locations have contributed to increased flowback volumes. In addition to disposing of saltwater, our saltwater gathering and transportation assets are capable of recycling saltwater and returning it to our fresh water system for future use.

Market Fundamentals

According to the U.S. Energy Information Administration, or the EIA, both total energy supply and demand are projected to grow in coming decades. Population is one key determinant of energy consumption through its influence on demand for travel, housing, consumer goods and services. The EIA anticipates the total U.S. population will increase by 20% from 2013 to 2040. The EIA forecasts U.S. energy consumption to increase 9% over the same period. A review of other supply and demand elements follows.

Crude Oil Consumption

Crude oil is a significant component of energy consumption in the United States. According to the EIA, liquid petroleum consumption accounted for approximately 37% of all energy used in the United States in 2013. Global petroleum liquids consumption is expected to grow 33% from 91 million barrels a day in 2013 to 121 million barrels per day by 2040. The following charts illustrate expected growth in petroleum and other liquids consumption.

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Global Petroleum Liquids Consumption: 2013-2040

Source: EIA, Annual Energy Outlook 2015 (April 2015).

Forecasts published by the EIA anticipate continued growth in the long-term global demand for crude oil. These forecasts are supported by various factors, including: (i) continued global population growth, which has a significant influence on long-term growth in crude oil demand; (ii) GDP growth for both OECD and non-OECD countries; (iii) increased transportation activity, offset by increased vehicle fuel economy; (iv) increased industrial activity; and (v) the emergence of low-cost tight crude oil shale developments.

Crude Oil Production

Onshore Unconventional Production

Unconventional basins in the United States and Canada are rapidly changing the crude oil market dynamics in North America. The growth in crude oil production across North America is being driven by new technologies, such as horizontal drilling and hydraulic fracturing, which are unlocking vast quantities of crude oil and natural gas reserves. According to the EIA, North American onshore production grew at an annual rate of approximately 20% from 2010 to 2013 and is expected to grow at an annual rate of approximately 5% from 2013 to 2020. From 2010 to 2013, tight oil production grew at an annual rate of approximately 57% and is expected to grow at an annual rate of approximately 9% from 2013 to 2020.

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The chart below depicts the estimated increase in North American onshore crude oil production through 2020.

U.S. Lower 48 Onshore Crude Production: 2010-2020

Source: EIA, Annual Energy Outlook 2015 (April 2015).

Crude Oil Prices

Average annual U.S. crude oil prices have decreased significantly over the past year as a result of the availability of abundant domestic resources and the application of improved production technologies. Over the past two years, growth in U.S. crude oil production, along with the late-2014 drop in global crude oil prices, has altered the economics of the crude oil market. Nonetheless, the EIA projects that the average WTI crude oil spot price will increase through 2040, as growing demand leads to the development of more costly resources.

WTI Spot Crude Oil Price ($ per Bbl)

Source: EIA, Annual Energy Outlook 2015 (April 2015).

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The EIA’s projection of crude oil prices depends on many factors, including macroeconomic growth rates, changes in worldwide demand for petroleum products, crude oil production, and supplies of other liquid fuels. After 2018, growth in demand from non-OECD countries pushes the WTI price to $136/bbl in 2040 (in 2013 dollars). The increase in crude oil prices supports growth in domestic crude oil production.

Natural Gas Consumption

Natural gas is a significant component of energy consumption in the United States. According to the EIA, natural gas consumption accounted for approximately 28% of all energy used in the United States in 2013. Natural gas consumption is expected to grow 13% from 26.9 quadrillion BTU in 2013 to 30.5 quadrillion BTU by 2040. The following charts illustrate expected energy consumption by fuel source in 2040 as compared to 2013.

Forecasts published by the EIA anticipate continued growth in the long-term domestic demand for natural gas. These forecasts are supported by various factors, including (i) expectations of continued growth in the U.S. gross domestic product, which has a significant influence on long-term growth in natural gas demand; (ii) an increased likelihood that regulatory and legislative initiatives regarding domestic carbon policy will drive greater demand for cleaner burning fuels such as natural gas; (iii) increased acceptance of the view that natural gas is a clean and abundant domestic fuel source that can lead to greater energy independence of the United States by reducing its dependence on imported petroleum; (iv) the emergence of low-cost natural gas shale developments; and (v) continued growth in electricity generation from intermittent renewable energy sources, primarily wind and solar energy, for which natural-gas fired generation is a logical back-up power supply source.

The majority of fuel switching is occurring in electric power generation where coal-fired plants are being replaced with cleaner burning fuel sources. However, as a result of more rapid increases in generation from natural gas and renewable fuels, coal’s share of the total U.S. generation mix is projected to fall from 39% to 34% from 2013 to 2040. Over the same period, the share of U.S. generation from natural gas is projected to increase from 27% in 2013 to 31% in 2040.

U.S. Electricity Generation by Fuel Source: 2000-2040

Source: EIA, Annual Energy Outlook 2015 (April 2015).

In addition to increasing domestic consumption, domestic natural gas consumers will also compete for supply with foreign natural gas consumers. According to the EIA, the United States is expected to become an overall net exporter of natural gas in 2017. This shift from being a net importer of natural gas to a net exporter of

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natural gas is driven by the increased use of LNG in markets outside of North America, strong domestic production, and relatively low U.S. natural gas prices in comparison with other global markets. The following chart illustrates the trend of overall domestic natural gas net imports shifting to net exports by 2017.

U.S. Net Imports of Natural Gas: 2005-2040

Source: EIA, Annual Energy Outlook 2015 (April 2015).

Natural Gas Production

In response to increased domestic energy consumption, total domestic energy production is projected to grow significantly over the next 25 years. The EIA estimates that total U.S. energy production will increase by 29%, from 82.7 to 106.6 quadrillion Btu, and natural gas production will increase by 45%, from 25.1 to 36.4 quadrillion Btu, between 2013 and 2040. The chart below shows the total production for fuel sources through 2040.

Energy Production by Domestic Fuel Source: 2013-2040

Source: EIA, Annual Energy Outlook 2015 (April 2015).

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Domestic natural gas consumption today is satisfied primarily by production from conventional and unconventional onshore and offshore production in the lower 48 states, and is supplemented by production from historically declining pipeline imports from Canada, imports of LNG from foreign sources and some Alaska production. In order to maintain current levels of U.S. natural gas supply and to meet the projected increase in demand, new sources of domestic natural gas must continue to be developed to offset natural depletion associated with existing production.

Over the past several years, a fundamental shift in production has emerged with the contribution of natural gas from shale increasing from 8.1% of total U.S. natural gas gross withdrawals in 2007 to 39.6% in 2013. According to the EIA, during the four-year period from 2009 through 2013, domestic natural gas marketed production increased by 4.4% per annum, largely due to continued development of shale resources. The emergence of shale plays has resulted primarily from advances in horizontal drilling and hydraulic fracturing technologies, which have allowed producers to extract significant volumes of natural gas from these plays at cost-advantaged per unit economics versus most conventional plays.

As the depletion of conventional onshore and offshore resources continues, natural gas from unconventional resource plays is forecasted to fill the void and continue to gain market share from higher-cost sources of natural gas. As shown in the graphic below, natural gas production from the major shale formations is forecast to provide the majority of the growth in domestically produced natural gas supply, increasing to approximately 55% in 2040 as compared with 46% in 2013. The increase in natural gas production from 2013 to 2040 results primarily from continued exploration and development of shale gas resources. Shale gas is the largest contributor to production growth, while production from tight sands, coalbed methane deposits and offshore waters remains relatively stable.

U.S. Natural Gas Production by Source: 2013-2040

Source: EIA, Annual Energy Outlook 2015 (April 2015).

The abundance of natural gas shale production as well as the divergence between U.S. domestic and international prices for natural gas has caused a renewed interest in exporting domestic natural gas through LNG export terminals. While these projects take many years to develop, some domestic producers and foreign consumers view them as attractive opportunities to improve their respective economics and provide for an alternative source of demand for natural gas.

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Natural Gas Prices

Average annual U.S. natural gas prices have remained relatively low over the past several years as a result of the availability of abundant domestic resources and the application of improved production technologies. Nonetheless, the EIA projects that growth in demand for natural gas, largely from the electric power and industrial sectors, exports to Mexico and demand for liquefied natural gas exports, will result in upward pressure on prices through 2040.

Henry Hub Spot Natural Gas Price ($ per million BTU)

Source: EIA, Annual Energy Outlook 2015 (April 2015).

The EIA’s projection of natural gas prices depends on many factors, including macroeconomic growth rates and expected rates of resource recovery from natural gas wells. Higher rates of economic growth are expected to lead to increased consumption of natural gas, primarily in response to their effects on housing starts, commercial floor space and industrial output. Furthermore, the rate of resource recovery from crude oil and natural gas wells is expected to have a direct impact on the cost per unit of production and, in turn, prices.

The development of shale gas resources are expected to spur growth in natural gas production, with producers seeing higher prices as a result of growing demand, especially from both the industrial and electricity generation sectors. Growing LNG exports also support higher natural gas prices in the projection period. U.S. pipeline exports of natural gas—most flowing south to Mexico—have grown substantially since 2010 and are projected to continue increasing through 2040. According to the EIA, the United States will become a net exporter of natural gas in 2017, driven by LNG exports, increased pipeline exports to Mexico and reduced imports from Canada.

Overview of the DJ Basin

General

Since the implementation of horizontal drilling technology, the DJ Basin has become recognized as a premier U.S. liquids resource play. As Noble’s largest onshore field by proved reserves, average daily production and wells drilled, the DJ Basin was a key driver of Noble’s increase in production and cash flows through 2014.

The DJ Basin is a structural basin located in eastern Colorado, southeastern Wyoming, western Kansas, and the Nebraska Panhandle and covers an area of more than 42,000 square miles. The basin has a long history of crude oil and natural gas exploration and production, predominantly from an area described as the Wattenberg

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field. According to the EIA, the Wattenberg Field is the fourth largest producing crude oil field and ninth largest producing natural gas field in the United States by 2013 estimated production. While historically a natural gas-focused field, the Wattenberg is also known for its high liquids content, evidenced by the significant growth in crude oil production from the Niobrara and Codell shale formations. The Niobrara Shale formation is situated in portions of Colorado, Wyoming, Nebraska, and Kansas as shown below.

DJ Basin

Source: EIA.

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The DJ Basin has experienced a significant ramp in activity since 2012. As depicted below, monthly crude oil and natural gas production in Weld County, Colorado, increased 157% from January 2012 to March 2015.

Historical Weld County Monthly Crude Oil & Natural Gas Production: January 2012—March 2015

Source: Colorado Oil & Gas Conservation Commission.

History

The history of crude oil and natural gas production in the DJ Basin dates back to the first discovery that occurred in 1865 at the Florence Field. The first commercial discovery was made in 1901 at the Boulder Field with production coming from the Codell sandstone. Later, in 1919, the Beecher Island Field began producing natural gas from the Niobrara Chalk. Other large DJ Basin discoveries include the Wellington Field, discovered in 1923, and the Greasewood Field, discovered in 1930. In 1970, the Wattenberg Field was discovered with production coming from the Muddy/J Sandstone.

Geology

The Niobrara formation is uniformly present across the entire DJ Basin with an average depth of approximately 7,200 feet in the core Wattenberg Field. The formation consists of chalky benches created from skeletal debris of planktonic organisms deposited in a shallow marine environment. The Niobrara A, B and C benches serve as a source rock that generates crude oil and natural gas. Including the Codell formation, which is located just below the Niobrara benches, the crude oil and natural gas saturated interval ranges from 300 to 350 feet thick. The Niobrara’s shale and chalk intervals are characterized by high density porosity of 10% to 14% and low permeability. The formation has a high storage capacity for hydrocarbons and requires multiple wells per section to adequately drain the recoverable crude oil and natural gas, leading operators to test tighter well spacing. The Codell formation is considered to be a part of the same petroleum system as the Niobrara and has an average depth of approximately 7,300 feet.

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BUSINESS

Overview

We are a growth-oriented Delaware master limited partnership recently formed by our sponsor, Noble, to own, operate, develop and acquire a wide range of domestic midstream infrastructure assets. We currently provide crude oil, natural gas, and water-related midstream services for Noble through long-term, fixed-fee contracts. Our operating assets are currently focused in the DJ Basin in Colorado, one of the premier liquid hydrocarbon basins in the United States. Noble intends for us to become its primary vehicle for domestic midstream operations that have not previously been dedicated to other ventures. We believe that our diverse midstream infrastructure assets and our relationship with Noble position us as a leading midstream service provider.

We have entered into multiple fee-based commercial agreements with Noble, each with an initial term of 15 years, utilizing our infrastructure assets to provide an array of services critical to Noble’s upstream operations. Our agreements include substantial acreage dedications. See “—Our Acreage Dedication.” These long-term, fee-based commercial agreements are intended to mitigate our direct commodity price exposure and enhance the stability of our cash flows. In the future, we intend to seek similar commercial arrangements with unaffiliated third parties.

Noble is one of the largest producers of liquids in the DJ Basin, where it produced, on average, 101 MBoe/d of crude oil, condensate, natural gas and NGLs during 2014, with 66% of such volumes being crude oil and NGLs. Noble’s sales volumes in the DJ Basin increased to 116 MBoe/d in the three months ended March 31, 2015, with 64% of such volumes being crude oil and NGLs. For the three months ended March 31, 2015, we provided crude oil and natural gas gathering services with respect to an average of approximately 31 MBoe/d. As of December 31, 2014, Noble’s estimated net proved reserves in the DJ Basin were 451 MMBoe, of which approximately 61% was crude oil, condensate and NGLs.

Noble commenced horizontal drilling in the DJ Basin in 2010 in order to increase recoveries of liquid-rich hydrocarbons. This shift to a horizontal drilling program has created an opportunity for more efficient gathering of crude oil, natural gas, NGLs and water, which is the core of our business. Noble is testing a number of drilling and completion techniques to increase efficiencies and ultimate recovery while enhancing the overall value of its DJ Basin position. Noble accelerated its extended reach lateral well program to approximately 32% of wells drilled in 2014. During the year ended December 31, 2014, Noble spud 303 horizontal wells, of which 96 were extended reach lateral wells, and 310 wells initiated production. Since January 2010, Noble has spud over 900 horizontal wells, covering over four million lateral feet.

The table below shows Noble’s DJ Basin drilling activities for the past three years ended December 31.

	Year Ended December 31,
	2012		2013		2014
Number of horizontal wells spud		193		285		303
Approximate average lateral feet per horizontal well		4,200		4,400		5,600

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The graph below shows Noble’s DJ Basin horizontal production and drilling activity from January 1, 2010 through March 31, 2015, and demonstrates the impact that the horizontal drilling program has had on Noble’s DJ Basin production. A number of factors impact Noble’s production and drilling activity, including the number of drilling rigs that Noble operates on its acreage. See “Risk Factors—Risks Related to Our Business.”

In addition to its DJ Basin assets, pursuant to its acquisition of Rosetta Resources Inc. completed on July 20, 2015, Noble acquired certain Eagle Ford Shale and Permian Basin assets. Noble anticipates a compounded annual production growth rate from its newly acquired Eagle Ford Shale and Permian Basin assets over the next several years of approximately 15% in aggregate. These assets had proved reserves of 282 MMBoe for the year ended December 31, 2014 and average production for the second quarter of 2015 of approximately 63 MBoe/d. More than 60% of the current production and proved reserves for these assets are liquids.

Our Existing Assets

We operate and own interests in crude oil gathering pipelines, crude oil treating facilities, natural gas gathering pipelines and a CGF. In addition, we provide Noble with water-related services that are critical to Noble’s upstream operations, including the storage and distribution of fresh water for use in drilling and completion operations and collecting, cleaning, recycling and disposing of saltwater, through our interests in pipelines and facilities (or under contracts with third parties). The majority of our current facilities are located in two areas of Weld County, Colorado, that we refer to as the Wells Ranch IDP and the East Pony IDP. Each IDP area consists of a large block of Noble’s contiguous acreage, allowing us to build and operate midstream infrastructure that we believe is more efficient in terms of capital invested per mile of pipe and service provided.

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Noble develops the IDP areas through a comprehensive design for well pad facilities that support horizontal drilling allowing us to efficiently gather production and provide midstream services to these areas with reduced truck traffic, emissions and overall surface footprint.

To effectively manage our growth, capital expenditure requirements and balance sheet, we have divided our initial assets and those that we expect to develop in the future between two categories, which we refer to as our “Core Assets” and “Growth Assets,” based on their current expected cash flows, growth profiles, capital expenditure requirements and the expected timing of their development.

Core Assets

Our Core Assets include the assets that generate substantially all of our current cash flows. We expect these assets to be key contributors to our growth in the near-term as Noble continues to increase its production in the DJ Basin through the execution of its horizontal drilling plan. Except for our interest in White Cliffs LLC described below, all of our Core Assets are owned by a development company in which we own an initial             % controlling interest.

Our Core Assets include gathering systems in the Wells Ranch IDP that collect crude oil, natural gas and saltwater from facilities located at or near the wellhead and provide gathering to the Wells Ranch CGF or other delivery points within the IDP area. At the Wells Ranch CGF, we provide certain integral services, including separation, treatment, cleaning and storage of the incoming liquid stream into pipeline-quality crude oil and saltwater suitable for disposal or recycling operations. At the tailgate of the Wells Ranch CGF, we deliver the hydrocarbons to a third party for additional gathering and processing and we collect and clean the saltwater and prepare it for treating, recycling and disposal, with a portion of this water returning to our fresh water system after recycling. We expect these systems and others that we may develop in other IDP areas in the future will provide us and Noble many benefits, including increased capital and operating efficiencies. Our Core Assets servicing the Wells Ranch IDP include:

• approximately 25 miles of liquids pipelines that carry both crude oil and saltwater servicing the Wells Ranch IDP, which had, during the three months ended March 31, 2015:

o average daily throughput of approximately 16,800 Bbl/d of crude oil; and

o average daily throughput of approximately 3,600 Bbl/d of saltwater;

• approximately 30 miles of natural gas gathering pipelines servicing the Wells Ranch IDP, which had average daily throughput of approximately 63,400 Mcf/d as of March 31, 2015;

• storage capacity for up to 96,000 Bbls of crude oil and 32,000 Bbls of saltwater at the Wells Ranch CGF;

• approximately 20 miles of fresh water pipelines servicing the Wells Ranch IDP that delivered an average of approximately 2,000 Bbl/d of fresh water during the three months ended March 31, 2015; and

• a fresh water storage system servicing the Wells Ranch IDP, which had a storage capacity of 500,000 Bbls of fresh water as of March 31, 2015.

In addition to our assets servicing the Wells Ranch IDP, we operate the following Core Assets:

• approximately 15 miles of crude oil gathering pipelines servicing the East Pony IDP, which had average daily throughput of approximately 2,600 Bbl/d of crude oil during the three months ended March 31, 2015;

• the Briggsdale and Platteville crude oil treating facilities, which have an annual operating capacity of 1,825,000 Bbls and 2,740,000 Bbls, respectively.

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In addition to the Core Assets described above, all of which are owned by a development company that we control, we own a 3.33% ownership interest in White Cliffs LLC. White Cliffs LLC owns the White Cliffs Pipeline, a crude oil transportation pipeline system consisting of two 527-mile parallel pipelines that transport crude oil from Platteville, Colorado, in the DJ Basin to Cushing, Oklahoma. Our ownership interest entitles us to distributions based on our pro rata share of monthly net cash flow generated by the operation of the White Cliffs Pipeline, which is managed and operated by Rose Rock Midstream, L.P. and its affiliates. The White Cliffs Pipeline has a current capacity of approximately 150,000 Bbl/d of crude oil and is undergoing an expansion to increase the pipeline’s crude oil capacity to approximately 215,000 Bbl/d in late 2015.

Growth Assets

Our Growth Assets are held by a number of development companies in which we own initial controlling interests ranging from     % to     %. We believe this tiered ownership structure will allow us to maintain flexibility to adjust to Noble’s development decisions. Our Growth Assets include:

• the East Pony IDP fresh water system, which consists of approximately 10 miles of pipelines and a storage capacity of 550,000 Bbls of water as of March 31, 2015 and an average daily throughput of approximately 25,000 Bbl/d during the three months ended March 31, 2015;

• surface leases with partial construction of fresh water systems and rights-of-way located in the Mustang IDP that will permit crude oil, natural gas and water infrastructure to be constructed and a dedication from Noble covering production from Noble’s net mineral acreage in the Mustang IDP pursuant to which we are entitled to provide all crude oil, natural gas and water midstream services that were not previously dedicated to a third party;

• a dedication from Noble covering production from Noble’s net mineral acreage in the Greeley Crescent IDP pursuant to which we are entitled to provide crude oil and water midstream services; and

• a dedication from Noble covering production from Noble’s net mineral acreage in the Bronco IDP pursuant to which we are entitled to provide crude oil and water midstream services.

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The following table provides a summary of our assets, services and dedicated net acreage (as of March 31, 2015) along with our ownership of these assets as of the closing of this offering.

	Area Served	NBLX Dedicated Service	Approximate Dedicated Net Acreage	NBLX Ownership Interest
Core Assets(1)	Wells Ranch IDP	•    Crude Oil Gathering •    Natural Gas Gathering(2) •    Water Services	65,000	%
	East Pony IDP All Noble DJ Basin Acreage	•    Crude Oil Gathering •    Crude Oil Treating	40,000 N/A(3)
Growth Assets	Mustang IDP(4)	•    Crude Oil Gathering •    Natural Gas Gathering(2) •    Water Services	80,000	%
	Greeley Crescent IDP(4)	•    Crude Oil Gathering •    Water Services	65,000	%
	Bronco IDP(4)	•    Crude Oil Gathering •    Water Services	50,000	%
	East Pony IDP	•    Water Services	40,000	%

(1) Our Core Assets also include a 3.33% ownership interest in White Cliffs LLC, which is not held through a development company.

(2) We provide natural gas gathering services in the Wells Ranch IDP, and we expect to provide natural gas gathering services in the Mustang IDP, from Noble’s centralized wellhead equipment to third parties. See “—Our Existing Assets.”

(3) We charge Noble fixed fees based on the number of Noble-operated wells with access to our crude oil treating facilities. As of March 31, 2015, we serviced and collected fees in respect of 6,340 Noble-operated wells at our crude oil treating facilities.

(4) We currently have limited midstream infrastructure assets in the Mustang IDP and no midstream infrastructure assets in the Greeley Crescent IDP and Bronco IDP. Our assets in these IDP areas currently consist primarily of dedications to us from Noble for future production in these IDP areas. In the Mustang IDP, we also own certain rights-of-way and surface leases. See “—Our Existing Assets.”

Business Strategies

Our principal business objectives are to generate stable cash flows and increase the quarterly cash distributions that we pay to our unitholders over time while ensuring the ongoing stability of our business by providing outstanding service to our upstream customers. We expect to achieve these objectives through the following business strategies:

• Acting as the primary provider of midstream services in Noble’s dedicated areas. Our midstream infrastructure currently serves Noble’s production on its substantial acreage in the DJ Basin, from which Noble produced an average of 116 MBoe/d of crude oil, condensate, natural gas and NGLs during the first quarter of 2015. During this time period, we provided crude oil and natural gas gathering services with respect to an average of approximately 31 MBoe/d. Noble has dedicated, until 2030, certain

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midstream services to us on this substantial acreage position in the DJ Basin. See “—Our Acreage Dedication.” We expect Noble’s production volumes to grow from its future horizontal drilling activities, which we anticipate will help us maintain and grow throughput on our crude oil, natural gas and saltwater midstream infrastructure and increase demand for our fresh water services. We are strategically positioned to expand our delivery of midstream services within the areas dedicated to us as Noble executes on its drilling and development plans.

• Pursuing accretive acquisitions from Noble and third parties. After this offering, Noble will be the sole owner of our general partner and will own a     % limited partner interest in us, consisting of          common units and all of our subordinated units and incentive distribution rights and its retained non-controlling interests in our Core Assets and Growth Assets. Noble has granted us a ROFR on its retained interests in the development companies that hold our assets as well as certain midstream assets that it retains, acquires or develops in the future to the extent such assets are not subject to a third party purchase right, including any assets acquired in connection with its acquisition of Rosetta Resources Inc. on July 20, 2015. We expect Noble to be strongly incentivized to help us grow our business, including by offering us the opportunity to acquire midstream assets it has retained, develops or acquires in the future and elects to sell. In addition, we expect to identify and pursue accretive third-party acquisitions.

• Attracting third-party business. In addition to being an integral provider of midstream services for Noble’s production in the DJ Basin, we intend to market our services to, and pursue strategic relationships with, third-party producers over the long term. We believe that our portfolio of assets and execution and operational capabilities will position us favorably to compete for third-party production both inside and outside the DJ Basin. However, we do not know when or if such relationships with third-party producers will develop.

• Focusing on stable, fixed-fee arrangements to mitigate our direct commodity price exposure and enhance the stability of our cash flows. Our commercial agreements with Noble are structured as long-term, fixed-fee arrangements, and we intend to continue to pursue additional long-term, fixed-fee arrangements with Noble and third parties. We will pursue additional long-term commitments from customers, which may include throughput-based charges, reservation-based charges, volume commitments or acreage dedications.

Competitive Strengths

We believe we are well-positioned to successfully execute our business strategies because of the following competitive strengths:

• Strategic relationship with Noble. We have a strategic relationship with Noble, one of the leading producers of crude oil, condensate, natural gas and NGLs in the DJ Basin and North America. As the owner of our general partner, all of our incentive distribution rights, a     % limited partner interest in us and its retained, non-controlling interests in the development companies that hold our assets, we believe Noble will be incentivized to promote and support our business plan and to pursue projects that enhance the overall value of our business. Through our long-term commercial agreements with Noble, we have a well-capitalized, investment grade commercial counterparty initially responsible for all of our revenues. We believe that our relationship with Noble will provide us with a stable base of cash flows and significant growth opportunities.

• Strategically located assets. Our initial midstream infrastructure assets are located on and around Noble’s significant, contiguous acreage in the DJ Basin and serve Noble’s current and future production on this acreage. Noble commenced operations in Weld County, Colorado, in 2005 and currently holds one of the largest acreage positions in the DJ Basin. The DJ Basin has been the focus of extensive industry activity over the last several years, and we expect producers to continue to invest substantial

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capital to develop crude oil and natural gas production in this region, which will in turn require substantial investment in midstream infrastructure. We also expect Noble’s use of integrated development plans to help us manage capital expenditures because Noble’s development under these plans is intended to centrally locate production and midstream infrastructure rather than replicate services and infrastructure at each wellhead, which will allow us to efficiently gather Noble’s production from centralized wellhead equipment. In addition, Noble’s strategic, contiguous acreage provides us an opportunity to provide water-related services both at the initial stages of well development and at the tailgate of our midstream facilities. We believe that our existing footprint, coupled with Noble’s dedications, positions us to capitalize on midstream growth opportunities on Noble’s contiguous DJ Basin acreage.

• Long-term, fixed-fee contracts to support cash flows. We service Noble’s liquids-rich production in the DJ Basin pursuant to long-term, fixed-fee contracts. For the twelve months ended March 31, 2015, Noble represented all of our gathering volumes. We have secured dedications from Noble under which we will provide our crude oil, natural gas and water services pursuant to 15-year, fixed-fee contracts. We believe that Noble’s horizontal drilling activity and potential new third-party customers will drive the stable growth of our midstream operations. Our contract structure mitigates our direct exposure to commodity price risk contributing to long-term cash flow stability.

• Financial flexibility and strong capital structure. At the closing of this offering, we expect to have $         million of availability under our new, undrawn revolving credit facility. We believe that our available borrowing capacity and our expected ability to access debt and equity capital markets provide us with the financial flexibility necessary to execute our business strategy.

• Experienced management and operating teams. Our executive management team has an average of over              years of experience in designing, acquiring, building, operating, financing and otherwise managing large-scale midstream and other energy assets. In addition, through our omnibus services agreement with Noble, we employ engineering, construction and operations teams that have significant experience in designing, constructing and operating large scale midstream and other energy assets.

Noble Energy, Inc.

Overview

Noble is a global independent oil and natural gas exploration and production company, with total proved reserves of 1.7 billion Boe at year-end 2014 (pro forma for the acquisition of Rosetta Resources Inc.). Noble’s diverse resource base includes positions in four premier unconventional U.S. onshore plays—the DJ Basin, Marcellus Shale, Eagle Ford Shale and Permian Basin—and offshore in the U.S. Gulf of Mexico, Eastern Mediterranean and West Africa. Noble is listed on the NYSE under the symbol “NBL” and had a market capitalization of approximately $16.5 billion as of December 31, 2014.

Noble is one of the largest producers of liquids in the DJ Basin, where it produced, on average, 101 MBoe/d of crude oil, condensate, natural gas and NGLs during 2014, with 66% of such volumes being crude oil and NGLs. Noble’s sales volumes in the DJ Basin increased to 116 MBoe/d in the three months ended March 31, 2015, with 64% of such volumes being crude oil and NGLs. As of December 31, 2014, Noble’s reported estimated net proved reserves in the DJ Basin were 451 MMBoe, of which approximately 61% was crude oil, condensate and NGLs.

Noble continually evaluates strategic additions to its reserves in North America. On July 20, 2015, Noble acquired approximately 50,000 net acres in the Eagle Ford Shale in south Texas and 56,000 net acres in the Permian Basin in west Texas (46,000 net acres in the Delaware Basin and 10,000 net acres in the Midland Basin) in connection with its acquisition of Rosetta Resources Inc. Noble has identified in excess of 1,800 gross horizontal drilling locations for development in this newly acquired acreage.

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Our Relationship with Noble

One of our principal strengths is our relationship with Noble. In connection with the completion of this offering, we will (i) issue             common units and             subordinated units to Noble, representing 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), (ii) issue a non-economic general partner interest in us to our general partner and issue all of our incentive distribution rights to Noble and (iii) use the net proceeds from this offering to make a distribution of approximately $         million to Noble. Please read “Prospectus Summary—The Offering,” “Use of Proceeds,” “Security Ownership of Certain Beneficial Owners and Management” and “Certain Relationships and Related Party Transactions—Distributions and Payments to Our General Partner and Its Affiliates.”

Given Noble’s significant ownership interest in us following this offering and its intent to use us as its primary domestic midstream service provider in areas that have not previously been dedicated to other ventures, we believe that Noble will be incentivized to promote and support the successful execution of our business strategies; however, we can provide no assurances that we will benefit from our relationship with Noble. While our relationship with Noble is a significant strength, it is also a source of potential risks and conflicts. Please read “Risk Factors—Risks Inherent in an Investment in Us” and “Conflicts of Interest and Duties.”

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Our Midstream Operations

Areas of Operation

Substantially all of our operating assets are located in Weld County in northern Colorado. The majority of our assets are strategically located to service Noble’s production from the Wells Ranch IDP and East Pony IDP. In addition, Noble has dedicated future production from the Mustang IDP, Greeley Crescent IDP and Bronco IDP to us for the provision of certain midstream services. In the aggregate, these IDP areas cover approximately 300,000 net acres. As of March 31, 2015, over $230 million has been invested in the infrastructure that we operate.

Wells Ranch. The Wells Ranch IDP describes an area in Weld County, Colorado, that includes approximately 65,000 net acres operated by Noble. Noble has dedicated this acreage to us for crude oil services, certain natural gas gathering services and water services. Our assets that service the Wells Ranch IDP include crude oil, natural gas, fresh water and saltwater infrastructure. The gathering systems servicing this area are connected to the Wells Ranch CGF, which is located in the northern portion of the Wells Ranch IDP. The fresh water facilities are located throughout the Wells Ranch IDP.

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East Pony. The East Pony IDP describes an area in Weld County, Colorado, that includes approximately 40,000 net acres operated by Noble. Noble has dedicated this acreage to us for crude oil gathering and water services. Our assets that service the East Pony IDP include crude oil gathering systems and a fresh water system.

Mustang. The Mustang IDP describes an area in Weld County, Colorado, that includes approximately 80,000 net acres operated by Noble. We will own rights-of-way in this area that will permit crude oil gathering, certain natural gas gathering services and water services. We anticipate commencing construction of crude oil gathering pipelines, fresh water systems, natural gas gathering pipelines, saltwater gathering lines, and other water infrastructure in this area if and when Noble begins production in this area.

Greeley Crescent. The Greeley Crescent IDP describes an area in Weld County, Colorado, that includes approximately 65,000 net acres operated by Noble. Noble has dedicated this acreage to us for crude oil gathering and water services.

Bronco. The Bronco IDP describes an area in Weld County, Colorado, that includes approximately 50,000 net acres operated by Noble. Noble has dedicated this acreage to us for crude oil gathering and water services.

Additional DJ Basin Services. The two crude oil treating facilities, further described below, are located in or near IDP areas. As these facilities treat crude oil that is trucked to them, these facilities serve vertical and horizontal wells throughout the DJ Basin.

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Midstream Infrastructure Assets

Crude Oil Gathering and Treating

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Our crude oil gathering systems include approximately 40 miles of pipeline, 25 miles of which service the Wells Ranch IDP. Our crude oil gathering assets also include 96,000 Bbls of storage capacity at the Wells Ranch CGF. The 25-mile pipeline in the Wells Ranch IDP is a shared crude oil and saltwater gathering pipeline.

The Wells Ranch CGF separates the incoming liquid stream into pipeline-quality crude oil and saltwater suitable for disposal or recycling operations. The liquids entering the Wells Ranch CGF from the liquid gathering pipelines are a mixture of crude oil, saltwater and a small quantity of natural gas. The liquids are separated in the Wells Ranch CGF. Crude oil is sent to the crude oil storage tanks and saltwater are further cleaned and sent to the saltwater storage tanks. The Wells Ranch CGF has the capacity to store up to 96,000 Bbls of crude oil. At the Wells Ranch CGF, we are able to recover gas vapors from the crude oil and deliver this natural gas to Noble for delivery to downstream third parties.

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To service the East Pony IDP, we gather crude oil meeting pipeline specifications and deliver it directly into the northern extension of the Wattenberg Oil Trunkline and the Northeast Colorado Lateral of the Pony Express Pipeline. Crude oil gathering of production from the East Pony IDP is subject to FERC jurisdiction. See “—Regulation of Operations.” We began gathering crude oil in our system in March 2015.

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The table below sets forth our crude oil gathering operations as of and for the dates indicated.

	Year Ended December 31, 2014						Three Months Ended March 31, 2015					As of March 31, 2015
												Horizontal Wells
	Throughput Capacity (Bbl/d)			Average Daily Throughput (Bbl/d)			Throughput Capacity (Bbl/d)		Average Daily Throughput (Bbl/d)			Number of Wells		Approx. Average Lateral Feet per Well
Wells Ranch IDP		45,000			16,400			45,000		16,800			267		4,900
East Pony IDP		—	(1)		—	(1)		85,000		2,600	(1)		83		5,100

(1) The crude oil gathering infrastructure servicing the East Pony IDP was not placed into service until March 12, 2015.

We also operate two crude oil treating facilities, the Platteville and the Briggsdale facilities. These facilities service each of the IDP areas and additional wells that fall outside of these areas. The permits under which we operate the Platteville and Briggsdale facilities permit approximately 1,825,000 Bbls and 2,740,000 Bbls, respectively, of crude oil to be treated during any given year. Crude oil is delivered to the facilities by truck. If treatment is required, the crude oil is directed to, and received by, the treating facility to process the crude oil to meet pipeline specification. For access to and the services provided at the crude oil treating facilities service, Noble pays monthly fees based on the number of producing vertical wells and producing horizontal wells located in the DJ Basin that are not connected to our gathering system, whether such wells fall within or outside of an IDP area.

The table below sets forth our crude oil treating operations as of March 31, 2015.

	Annual Operating Capacity (Bbls)		Number of Wells Subject to Fee(1)
			Vertical	Horizontal
Platteville		1,825,000	5,800	540
Briggsdale		2,740,000

(1) We charge Noble a fixed fee based on the number of Noble-operated wells with access to our crude oil treating facilities.

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Natural Gas Gathering

As of March 31, 2015, our natural gas infrastructure assets consisted of the Wells Ranch CGF and an approximately 30-mile natural gas pipeline system servicing production from the Wells Ranch IDP. The natural gas gathering system that services the production from the Wells Ranch IDP collects wet gas from separator facilities located at or near the wellhead and delivers the wet gas to the Wells Ranch CGF or other delivery points within the Wells Ranch IDP. At the tailgate of our natural gas gathering facilities or the Wells Ranch CGF, as applicable, we deliver the natural gas for further gathering and processing by third parties.

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The table below sets forth our natural gas gathering operations as of and for the dates indicated.

Year Ended December 31, 2014

Three Months Ended March 31, 2015

As of March 31, 2015

Horizontal Wells

Throughput Capacity (Mcf/d)

Average Daily Throughput (Mcf/d)

Throughput Capacity (Mcf/d)

Average Daily Throughput (Mcf/d)

Number of Wells

Approx. Average Lateral Feet per Well

Wells Ranch IDP

75,000

55,100

150,000

63,400

267

4,900

Our Wells Ranch CGF provides condensate separation and flash gas recovery. Condensate recovered from the natural gas that is gathered to the Wells Ranch CGF is stored on location and gas that is flashed from the crude oil is recovered, compressed and redelivered to downstream third parties with the gathered natural gas volumes.

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Water Gathering and Distribution Systems

We provide Noble with water-related services that are integral to Noble’s upstream operations through our interests in pipelines and facilities (or under contracts with third parties) that store and distribute fresh water and collect, clean and recycle or dispose of saltwater. The majority of our midstream water assets are currently located in the Wells Ranch IDP and are linked to the Wells Ranch CGF. We developed infrastructure to service this IDP area, which contributes to Noble’s ability to drill and complete wells in the Wells Ranch IDP. At the tailgate of the Wells Ranch CGF, the saltwater that we collect and separate is prepared for cleaning, treating, recycling and disposal, with a portion of this water returning to our fresh water system after recycling.

We and Noble are committed to the treatment and recycling of saltwater in an effort to minimize the use of fresh water resources and mitigate the potential for adverse impact caused by drought. Furthermore, we and Noble recognize the importance and value of community and environmental stewardship gained by reducing the

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demand of fresh water supplies that may also serve neighboring communities, the riparian corridor or agricultural interests. Our commitment to recycling is evident by the integration of dedicated infrastructure on or adjacent to the Wells Ranch CGF, such as multiple storage tanks, pumps, and a bi-directional pipeline system that transports saltwater from the Wells Ranch CGF for treatment and then receives the treated water for recycling and use for subsequent exploration and production operations. We provide Noble with recycled, treated water in amounts and at sufficient quality to blend with fresh water sources on-site for use in hydraulic fracturing operations to reduce the net draft on freshwater sources.

Saltwater

Our current saltwater gathering systems in the Wells Ranch IDP gather and process liquids produced from operations and consist of a combination of separation and storage facilities, and permanent pipelines, as well as pumping stations to transport saltwater to disposal or recycling facilities. We operate an approximately 25-mile gathering pipeline system (which is a shared crude oil and saltwater gathering pipeline) servicing the Wells Ranch IDP. Crude oil and saltwater are separated and measured at facilities at or near the wellhead and recombined and delivered into our gathering system. At the Wells Ranch CGF, the incoming crude oil and saltwater liquid stream is separated, stored, and treated before the crude oil is delivered to a third-party pipeline. At the tailgate of the Wells Ranch CGF, the saltwater that we collect and clean is prepared for treating, recycling or disposal. The Wells Ranch CGF has the capacity to store up to 32,000 Bbls of saltwater while awaiting delivery to a recycling facility or disposal facility. We enter into and manage contracts with third party providers of any saltwater services that we do not perform ourselves.

The table below sets forth our saltwater operations servicing the Wells Ranch IDP as of and for the dates indicated.

Year Ended December 31, 2014

Three Months Ended March 31, 2015

As of March 31, 2015

Horizontal Wells

Throughput Capacity (Bbl/d)

Average Daily Throughput (Bbl/d)

Throughput Capacity (Bbl/d)

Average Daily Throughput (Bbl/d)

Number of Wells

Approx. Average Lateral Feet per Well

Wells Ranch IDP

15,000

5,400

15,000

3,600

267

4,900

Fresh Water System

Our fresh water system provides services for both recycled and treated saltwater and raw fresh water that has been withdrawn from a river or ground water, for example. Our fresh water services include distribution and storage services that are integral to Noble’s well drilling and completion operations in the DJ Basin.

Our fresh water system contains an approximately 30-mile fresh water distribution system made up of permanent buried pipelines, 10 miles of which service the East Pony IDP and 20 miles of which service the Wells Ranch IDP. In addition, our fresh water system includes fresh water storage facilities, temporary pipelines and pumping stations to transport fresh water throughout the pipeline networks. These systems are designed to reduce the costs of transporting water long distances by reducing or eliminating most trucking costs. The fresh water system provides storage capacity that segregates raw fresh water from saltwater that has been recycled and treated.

Through our fresh water systems, we provide services to Noble, which continues to hold title to the water. When Noble needs water for well development and completion operations, Noble either transports the water to temporary storage facilities near the applicable well(s) or we deliver the water in our delivery system as described above. We do not own the water nor own or operate fresh water sources, but instead our services are focused on the storage and distribution of the fresh water and recycled water delivered to us by Noble.

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The table below sets forth our fresh water services in the Wells Ranch IDP, East Pony IDP and Mustang IDP as of and for the dates indicated.

	Year Ended December 31, 2014								Three Months Ended March 31, 2015
	Distribution Capacity (Bpm)			Average Daily Throughput (Bbl/d)			Storage Capacity (Bbls)		Distribution Capacity (Bpm)			Average Daily Throughput (Bbl/d)			Storage Capacity (Bbls)
Wells Ranch IDP		160			15,700			500,000		160			2,000			500,000
East Pony IDP		160			12,100			550,000		160			25,000			550,000
Mustang IDP		—	(1)		—	(1)		230,000		—	(1)		—	(1)		230,000

(1) Consists of a fresh water system from Noble owned water wells to a storage pond. Water is currently distributed from the pond by truck.

Access to Downstream Markets

Crude Oil. After we gather or treat crude oil, the crude oil is redelivered to Noble and subsequent downstream crude oil pipelines and markets. Depending upon our specific system, after we gather or treat crude oil, Noble can further transport crude oil to one or more of the following: White Cliffs Pipeline to Cushing, Oklahoma; the Pony Express Pipeline to Cushing, Oklahoma; or to rail terminal(s) which can access the Gulf Coast, East Coast or West Coast markets.

Natural Gas. With respect to natural gas produced from the Wells Ranch IDP, the gathering that we provide concludes at a handful of points of delivery to a third party, with the primary delivery point located at the tailgate of the Wells Ranch CGF. We deliver the gathered natural gas to Noble at the interconnection points of our system with third party systems. Noble continues the transportation of this natural gas downstream by immediately delivering the natural gas that we gathered to a third party for either further gathering or for processing, followed by additional third-party transportation. First sales of the natural gas may occur at the terminus of our system or at the terminus of the third party pipelines. Residue gas downstream of the third-party processing plants that our assets interconnect with may access the Front Range, Cheyenne Hub, and Mid-Continent markets via the Colorado Interstate Gas High Plains and A/B pipelines or the Xcel Energy pipeline, depending on the specific processing plant the residue is allocated to.

NGLs. NGLs originating from natural gas that we gather from the Wells Ranch IDP that is processed by a downstream third-party processor can be delivered to the Bushton/Conway, Kansas NGL markets through the Overland Pass Pipeline or the DCP Wattenberg Pipeline or the Mt. Belvieu, Texas NGL market through the Front Range and Texas Express Pipelines, depending upon the location of the allocated NGL’s by the third party processor.

Our Acreage Dedication

We believe that Noble’s extensive acreage position in Weld County, Colorado, in excess of 400,000 net acres as of March 31, 2015, provides a strong platform to support our current operations and future growth. Noble has achieved substantial production growth in Weld County, Colorado, over the last five years. From 2010 through March 31, 2015, Noble spud over 900 horizontal wells in Weld County, Colorado, while operating approximately 7,200 vertical wells.

Noble has dedicated acreage to us based on the services we provide. As of January 1, 2015, Noble has dedicated to us, for a period of 15 years, subject to existing dedications or rights of first refusal, its available net acreage in the Wells Ranch IDP, East Pony IDP, Mustang IDP, Greeley Crescent IDP and Bronco IDP areas. Our commercial agreements with Noble provide that, in addition to our existing dedicated acreage, any future acreage

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that is acquired by Noble in these IDP areas, and that is not subject to a pre-existing third-party commitment, will be included in the dedication to us for midstream services, including gathering, processing and treating. Based on Noble’s dedication to us and previously granted conflicting dedications, we anticipate providing crude oil and water-related midstream services on any wells that Noble elects to drill in the Wells Ranch IDP, East Pony IDP, Mustang IDP, Greeley Crescent IDP and Bronco IDP, as well as certain natural gas gathering services on any wells drilled in the Wells Ranch IDP and Mustang IDP. The number of wells Noble may drill, and timing with respect to these wells, will depend on numerous factors (some of which are beyond their control and all of which are beyond our control), including commodity prices, weather, government regulation, geologic interpretation and the economic environment.

Dedications for Crude Oil and Water Services

Our dedicated acreage of approximately 300,000 net acres in Weld County, Colorado, gives us access to a highly contiguous, liquids-rich block of acreage for crude oil and water services. Substantially all of this dedicated acreage is held by production. The dedicated acreage could be reduced, however, under certain circumstances. See “Risk Factors—Risks Related to Our Business.” To the extent that Noble is operator on this acreage, production owned or controlled by Noble will be dedicated to us for all crude oil and water-related midstream services.

Stacked Dedications for Natural Gas Services

Prior to our formation, Noble and its predecessors-in-interest dedicated certain natural gas gathering and processing services with respect to production from the Wells Ranch IDP and the Mustang IDP to third parties. These third parties have the right to gather natural gas beginning at the Wells Ranch CGF or at other receipt points that have been established between Noble and such third parties. Even while honoring these prior dedications to such third parties, Noble has dedicated certain natural gas gathering services to us with respect to production from the Wells Ranch IDP and Mustang IDP. We deliver the natural gas that has passed through our systems back to Noble at the interconnection points with such third-party pipelines and Noble delivers the natural gas to such third parties.

As a result, Noble has dedicated production from approximately 65,000 net acres in the Wells Ranch IDP and approximately 80,000 net acres in the Mustang IDP to us for these natural gas gathering services. All natural gas gathering and processing services with respect to the production from these IDP areas that occurs downstream of the Wells Ranch CGF or other agreed points of interconnection with such third parties will continue to be dedicated to the applicable third parties until such prior dedication is otherwise waived.

Releases from Dedication

If we have an uncured default of any of our material obligations under any of our commercial agreements for more than 12 consecutive months or if we fail to timely complete the construction of the facilities necessary to provide the requested midstream services that we are required by the commercial agreements to provide to Noble, the affected acreage will be permanently released from the dedication to us and Noble will be free to engage a third party to provide the midstream services that we failed to provide in a timely fashion. Any permanent releases of Noble’s acreage from the dedication could materially adversely affect our business, financial condition, results of operations, cash flows and ability to make cash distributions.

Our commercial agreements provide that in certain situations the acreage dedicated by Noble can be temporarily or permanently released from our dedication. For more information see “—Our Commercial Agreements with Noble.”

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Our Commercial Agreements with Noble

General

Our assets are physically connected to, and integral to the operation of, Noble’s crude oil and natural gas production and fresh and saltwater requirements in the DJ Basin. We have entered into multiple long-term, fee-based commercial agreements, with annual price escalation clauses, to provide Noble with crude oil, natural gas and saltwater gathering services, crude oil treating and fresh water delivery and storage services. Our commercial agreements with Noble are currently the source of substantially all of the revenues we generate from our midstream operations.

Each of our commercial agreements with Noble is dated effective January 1, 2015 and has a 15-year initial term. Upon the expiration of the initial 15-year term, each agreement will automatically renew for subsequent one-year periods unless terminated by either us or Noble no later than 90 days prior to the end of the initial term or any subsequent one-year term thereafter. Our commercial agreements will run with the land and be binding on a transferee of any of our dedicated acreage.

Development Plans

Under each of our commercial agreements, Noble is obligated to provide us with a detailed development plan with respect to the expected production on our dedicated acreage. The development plans are intended to help us coordinate with Noble in order to maximize efficient development of the acreage covered by these agreements. To that end, updated development reports are delivered quarterly and cover the 36-month period following the month in which the development report is delivered. In addition, each report must also include Noble’s general long-term drilling and production expectations on the dedicated acreage for the three years following the date of the report. Based on the development reports delivered to us, we may provide Noble with a midstream system plan, which will describe how we plan to develop the system to meet the anticipated production of Noble.

How We Generate Revenue

As described below, we receive fees under our commercial agreements based on the type and scope of the midstream services we provide and based on the midstream system we use to provide our services.

• Crude Oil Gathering. Under the applicable crude oil gathering agreement or tariff, we receive a volumetric fee per Bbl for the crude oil gathering services we provide, which varies by area of operation.

• Crude Oil Treating Agreement. Under the crude oil treating agreement, we receive a monthly fee for each well producing in paying quantities that is not connected to our crude oil gathering systems during such month, and this fee varies based on whether the crude oil is produced from a horizontal or vertical well.

• Natural Gas Gathering Agreement. Under the natural gas gathering agreement, we receive a volumetric fee per MMBtu for the natural gas gathering services we provide, which varies by area of operation.

• Saltwater Services Agreement. Under the saltwater services agreement, we receive a volumetric fee per Bbl for collecting, cleaning, recycling or otherwise disposing of water produced from operating crude oil and natural gas wells in the dedication area.

• Fresh Water Services Agreement. Under the fresh water services agreement, we receive a volumetric fee per Bbl for delivering fresh water. The cost of storing the fresh water is embedded in the delivery fee.

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Under each of our commercial agreements, the fees we charge Noble are automatically increased each calendar year by a percentage calculated based on the change in the consumer price index. In addition, each year we will propose a redetermination of the fees charged under our various systems on an annual basis, taking into account, among other things, expected capital expenditures necessary to provide our services under the applicable development plan. However, if we and Noble are unable to agree on a fee redetermination (other than the automatic annual adjustment), the prior fee will remain in effect.

Right of First Refusal on Assets and Services

We have obtained from Noble a ROFR to provide all midstream services covered by our commercial agreements with it on acreage that Noble owns or acquires in North America, including Noble’s newly acquired Eagle Ford Shale and Permian Basin acreage. Our ROFR is subject to all preexisting dedications, rights of first refusal, rights of first offer and other preexisting encumbrances. To the extent Noble obtains a release of any preexisting dedications, rights of first refusal, rights of first offer and other preexisting encumbrances, the applicable acreage would become subject to our ROFR. Pursuant to our ROFR, Noble is required to offer us, prior to offering such opportunity to a third party, the opportunity to provide midstream services in North America to the extent that Noble is not otherwise obligated to offer these services to third parties so long as the midstream services are of the type contemplated in our commercial agreements. We believe that this ROFR will provide us an opportunity to develop organic growth. We are under no obligation to extend our midstream services to the acreage covered by the ROFR, and Noble is only required to offer the services in these areas to us to the extent that Noble elects to seek a third party service provider.

Because our ROFR is contingent on factors outside of our control, we are unable to estimate the midstream services, if any, that Noble will offer to us to provide in the future pursuant to these arrangements. See “Risk Factors—Risks Related to Our Business—We may not be able to economically accept an offer from Noble for us to provide services with respect to which we have a right of first refusal.”

In addition, Noble has provided us a ROFR covering all domestic midstream assets that Noble has retained or that it develops or acquires so long as such midstream assets are not subject to preexisting rights of first refusal, rights of first offer or other encumbrances in favor of third parties. The ROFR applies to all applicable assets that are owned by Noble, including Noble’s retained interests in the development companies through which we operate our midstream services.

Noble is under no obligation to offer to sell us any assets pursuant to the ROFR (unless and until it otherwise intends to sell or otherwise dispose of such assets). We are under no obligation to buy any assets from Noble, and we do not know when or if Noble will make any offers to sell assets to us. Please read “Certain Relationships and Related Party Transactions—Agreements with our Affiliates in Connection with the Transactions—Omnibus Agreement.” While we believe our ROFR is a significant positive attribute, it may also be a source of conflicts of interest. After the completion of this offering, Noble will own our general partner, and there will be substantial overlap between the officers and directors of our general partner and the officers and directors of Noble. Please read “Risk Factors—Risks Inherent in an Investment in Us” and “Conflicts of Interest and Duties.”

Title to Our Properties

Our real estate interests in land were acquired pursuant to easements, rights-of-way, permits, surface use agreements, joint use agreements, licenses and other grants or agreements from landowners, lessors, easement holders, governmental authorities, or other parties controlling the surface or subsurface estates of such land, or, collectively, Real Estate Agreements, that were issued to or entered into by Noble, one of its affiliates or one of their predecessors-in-interest and transferred to us. In the future we will acquire additional Real Estate Agreements in our own name or by transfer from Noble. We have acquired Real Estate Agreements and related

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interests without any material challenge known to us relating to the title to the land upon which the assets are located, and we believe that we have satisfactory rights and interests to conduct our operations on such lands. We have no knowledge of any challenge to the underlying title of any material real estate interests held by us or to our title to any material real property agreements, and we believe that we have satisfactory title to all of our material real estate interests.

We hold various rights and interests to receive, deliver and handle water in connection with Noble’s production operations, or, collectively, Water Interests, that also were obtained by Noble or its predecessor in interest and transferred to us. Pursuant to these Water Interests, Noble retains title to the water. In the future, we will also acquire additional Water Interests in our own name or by transfer from Noble as necessary to conduct such operations. We are not aware of any challenges to any Water Interests or to the use of any water or water rights related to Water Interests.

Under our omnibus agreement, Noble will indemnify us for any failure to have certain real estate interests, Real Estate Agreements or Water Interests necessary to own and operate our assets in substantially the same manner that they were owned and operated prior to the closing of this offering. Noble’s indemnification obligation will be limited to losses for which we notify Noble prior to the         anniversary of the closing of this offering and will be subject to a $         million aggregate deductible before we are entitled to indemnification. Some of our Real Estate Agreements and Water Interests may continue to be held by Noble or its affiliates until we have made the appropriate filings in the jurisdictions in which such assets are located and have obtained any consents, approvals and notices that are not obtained or provided prior to transfer. We will make these filings and notices and seek to obtain these consents upon completion of this offering.

Seasonality

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. These seasonal anomalies can increase demand for crude oil and natural gas during the summer and winter months and decrease demand for crude oil and natural gas during the spring and fall months. 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 Noble to execute its drilling and development plan and increase operating expenses associated with repairs or anti-freezing operations.

Competition

As a result of our relationship with Noble and the long-term dedications to our midstream assets, we do not compete with other midstream companies to provide Noble with midstream services to its existing upstream assets in Weld County, Colorado, and we will not compete for Noble’s business as it continues to develop upstream production in Weld County, Colorado. However, because of pre-existing dedications and rights of first refusal in favor of certain third parties, our ability to provide natural gas gathering and processing with respect to natural gas produced outside of the Wells Ranch IDP and Mustang IDP is subject to agreement from such third parties.

As we seek to expand our crude oil and water-related midstream services beyond Weld County, Colorado, and to expand our natural gas midstream services to additional areas within and beyond Weld County, Colorado, we will face a high level of competition, including major integrated crude oil and natural gas companies, interstate and intrastate pipelines, and companies that gather, compress, treat, process, transport, store or market natural gas. As we seek to expand to provide midstream services to third party producers, we will also face a high level of competition. Competition is often the greatest in geographic areas experiencing robust drilling by producers and during periods of high commodity prices for crude oil, natural gas or NGLs.

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Regulation of Operations

The midstream services we provide are subject to regulations that may affect certain aspects of our business and the market for our services.

Safety and Maintenance Regulation

We are subject to regulation by the United States Department of Transportation, or DOT, under HLPSA, and comparable state statutes with respect to design, installation, testing, construction, operation, replacement and management of pipeline facilities. HLPSA covers petroleum and petroleum products, including NGLs and condensate, and requires any entity that owns or operates pipeline facilities to comply with such regulations, to permit access to and copying of records and to file certain reports and provide information as required by the United States Secretary of Transportation. These regulations include potential fines and penalties for violations. We believe that we are in compliance in all material respects with these HLPSA regulations.

We are also subject to the NGPSA, and the Pipeline Safety Improvement Act of 2002. The NGPSA regulates safety requirements in the design, construction, operation and maintenance of natural gas pipeline facilities while the Pipeline Safety Improvement Act establishes mandatory inspections for all United States crude oil and natural gas transportation pipelines and some gathering pipelines in high-consequence areas within ten years. DOT, through the PHMSA, has developed regulations implementing the Pipeline Safety Improvement Act that requires pipeline operators to implement integrity management programs, including more frequent inspections and other safety protections in areas where the consequences of potential pipeline accidents pose the greatest risk to people and their property.

The Pipeline Safety and Job Creations Act, enacted in 2012, amended the HLPSA and NGPSA and increased safety regulation. This legislation doubles the maximum administrative fines for safety violations from $100,000 to $200,000 for a single violation and from $1.0 million to $2.0 million for a related series of violations, and provides that these maximum penalty caps do not apply to civil enforcement actions, establishes additional safety requirements for newly constructed pipelines, and requires studies of certain safety issues that could result in the adoption of new regulatory requirements for existing pipelines, including the expansion of integrity management, use of automatic and remote-controlled shut-off valves, leak detection systems, sufficiency of existing regulation of gathering pipelines, use of excess flow valves, verification of maximum allowable operating pressure, incident notification, and other pipeline-safety related requirements. PHMSA has undertaken rulemaking to address many areas of this legislation. Extending the integrity management requirements to our gathering pipelines would impose additional obligations on us and could add material cost to our operations. In addition, any material penalties or fines issued to us under these or other statues, rules, regulations or orders could have an adverse impact on our business, financial condition, results of operation and cash flows.

States are largely preempted by federal law from regulating pipeline safety but may assume responsibility for enforcing intrastate pipeline regulations at least as stringent as the federal standards. The Colorado Public Utilities Commission is the agency vested with intrastate natural gas pipeline regulatory and enforcement authority in Colorado. The Commission’s regulations adopt by reference the minimum federal safety standards for the transportation of natural gas. We do not anticipate any significant problems in complying with applicable federal and state laws and regulations in Colorado. Our natural gas transmission and regulated gathering pipelines have ongoing inspection and compliance programs designed to keep the facilities in compliance with pipeline safety and pollution control requirements.

In addition, we are subject to the requirements of the federal Occupational Safety and Health Act, or OSHA, and comparable state statutes, whose purpose is to protect the health and safety of workers, both generally and within the pipeline industry. Moreover, the OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable

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state statutes require that information be maintained concerning hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We and the entities in which we own an interest are also subject to OSHA Process Safety Management regulations, which are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals. These regulations apply to any process which involves a chemical at or above specified thresholds, or any process which involves flammable liquid or gas, pressurized tanks, caverns and wells in excess of 10,000 pounds at various locations. Flammable liquids stored in atmospheric tanks below their normal boiling point without the benefit of chilling or refrigeration are exempt from these standards. Also, the Department of Homeland Security and other agencies such as the EPA continue to develop regulations concerning the security of industrial facilities, including crude oil and natural gas facilities. We are subject to a number of requirements and must prepare Federal Response Plans to comply. We must also prepare Risk Management Plans under the regulations promulgated by the EPA to implement the requirements under the Clean Air Act to prevent the accidental release of extremely hazardous substances. We have an internal program of inspection designed to monitor and enforce compliance with safeguard and security requirements. We believe that we are in compliance in all material respects with all applicable laws and regulations relating to safety and security.

FERC and State Regulation of Natural Gas and Crude Oil Pipelines

The FERC’s regulation of crude oil and natural gas pipeline transportation services and natural gas sales in interstate commerce affects certain aspects of our business and the market for our products and services.

Natural Gas Gathering Pipeline Regulation

Section 1(b) of the Natural Gas Act of 1938, or NGA, exempts natural gas gathering facilities from the jurisdiction of the FERC under the NGA. We believe that our natural gas gathering facilities meet the traditional tests the FERC has used to establish a pipeline’s status as a gathering pipeline and therefore our natural gas gathering facilities should not be subject to FERC jurisdiction. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services has been the subject of substantial litigation and varying interpretations and the FERC determines whether facilities are gathering facilities on a case by case basis, so the classification and regulation of our gathering facilities may be subject to change based on future determinations by the FERC, the courts, or Congress. If the FERC were to determine that all or some of our gathering facilities or the services provided by us are not exempt from FERC regulation, the rates for, and terms and conditions of, services provided by such facilities would be subject to regulation by the FERC, which could in turn decrease revenue, increase operating costs, and, depending upon the facility in question, adversely affect our results of operations and cash flows.

The Energy Policy Act of 2005, or EPAct 2005, amended the NGA to add an anti-market manipulation provision. Pursuant to the FERC’s rules promulgated under EPAct 2005, it is unlawful for any entity, directly or indirectly, in connection with the purchase or sale of natural gas subject to the jurisdiction of the FERC, or the purchase or sale of transportation services subject to FERC jurisdiction: (1) to use or employ any device, scheme or artifice to defraud; (2) to make any untrue statement of material fact or omit a material fact; or (3) to engage in any act or practice that operates as a fraud or deceit upon any person. EPAct 2005 provided the FERC with substantial enforcement authority, including the power to assess civil penalties of up to $1,000,000 per day per violation, to order disgorgement of profits and to recommend criminal penalties. Failure to comply with the NGA, EPAct 2005 and the other federal laws and regulations governing our business can result in the imposition of administrative, civil and criminal remedies.

Colorado regulation of gathering facilities includes various safety, environmental and ratable take requirements. Our purchasing, gathering and intrastate transportation operations are subject to Colorado’s ratable take statute, which provides that each person purchasing or taking for transportation crude oil or natural gas from

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any owner or producer shall purchase or take ratably, without discrimination in favor of any owner or producer over any other owner or producer in the same common source of supply offering to sell his crude oil or natural gas produced therefrom to such person. This statute has the effect of restricting our right as an owner of gathering facilities to decide with whom we contract to transport natural gas. The ratable take statute is in the enabling legislation of the Colorado Oil and Gas Conservation Commission, or the COGCC.

The COGCC regulations require operators of natural gas gathering lines to file several forms and provide financial assurance, and they also impose certain requirements on gathering system waste. Moreover, the COGCC probably retains authority to regulate the installation, reclamation, operation, maintenance, and repair of gathering systems should the agency choose to do so. Should the COGCC exercise this authority, the consequences for the partnership will depend upon the extent to which the authority is exercised. We cannot predict what effect, if any, the exercise of such authority might have on our operations

Our natural gas gathering facilities are not subject to rate regulation or open access requirements by the Colorado Public Utilities Commission. However, the Colorado Public Utilities Commission requires us to register as pipeline operators, pay assessment and registration fees, undergo inspections and report annually on the miles of pipeline we operate.

Many of the producing states have adopted some form of complaint-based regulation that generally allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to natural gas gathering access and rate discrimination. Although Colorado does not have complaint-based regulation, additional rules and legislation pertaining to these matters are considered or adopted from time to time. 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.

Crude Oil Pipeline Regulation

Pipelines that transport crude oil in interstate commerce are subject to regulation by the FERC pursuant to the Interstate Commerce Act, or ICA, the Energy Policy Act of 1992, and related rules and orders. The ICA requires, among other things, that tariff rates for common carrier crude oil pipelines be “just and reasonable” and not unduly discriminatory and that such rates and terms and conditions of service be filed with the FERC. The ICA permits interested persons to challenge proposed new or changed rates. The FERC is authorized to suspend the effectiveness of such rates for up to seven months, though rates are typically not suspended for the maximum allowable period. If the FERC finds that the new or changed rate is unlawful, it may require the carrier to pay refunds for the period that the rate was in effect. The FERC also may investigate, upon complaint or on its own motion, rates that are already in effect and may order a carrier to change its rates prospectively. Upon an appropriate showing, a shipper may obtain reparations for damages sustained for a period of up to 2 years prior to the filing of a complaint. The rates charged for crude oil pipeline services are generally based on a FERC-approved indexing methodology, which allows a pipeline to charge rates up to a prescribed ceiling that changes annually based on the year-to-year change in the PPI. A rate increase within the indexed rate ceiling is presumed to be just and reasonable unless a protesting party can demonstrate that the rate increase is substantially in excess of the pipeline’s operating costs. During the five-year period commencing July 1, 2011 and ending June 30, 2016, pipelines have been permitted by the FERC to adjust these indexed rate ceilings annually by the PPI plus 2.65%. On June 30, 2015, the FERC issued its Notice of Inquiry requesting comments on its five year review of the index level in which the FERC proposes an index level between PPI plus 2.0% and PPI plus 2.4% for the five-year period commencing July 1, 2016. As an alternative to this indexing methodology, pipelines may also choose to support changes in their rates based on a cost-of-service methodology, by obtaining advance approval to charge “market-based rates,” or by charging “settlement rates” agreed to by all affected shippers.

Currently, only the crude oil gathering system servicing the East Pony IDP transports crude oil in interstate commerce. In compliance with the ICA, we are applying for a waiver of the tariff and rate requirements as

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they apply to our crude oil gathering system that services the East Pony IDP. If the FERC grants this waiver request, the FERC’s regulation of our crude oil gathering system servicing the East Pony IDP will be limited to requiring us to maintain our books and records consistent with the FERC’s recordkeeping requirements. If the FERC denies this waiver request, we will file a tariff with the FERC for our crude oil gathering system servicing the East Pony IDP. The tariff would set forth the rates for providing transportation services on the crude oil gathering system servicing the East Pony IDP as well as the rules and regulations governing these services. The FERC’s ratemaking methodologies and policies may limit our ability to set rates for our crude oil gathering system servicing the East Pony IDP based on our true costs or may delay the effectiveness of rates that reflect increased costs.

In addition to the crude oil gathering system servicing the East Pony IDP, we own interests in other crude oil gathering pipelines that do not provide interstate services and are not subject to regulation by the FERC. However, the distinction between FERC-regulated interstate pipeline transportation, on the one hand, and intrastate pipeline transportation, on the other hand, is a fact-based determination. The classification and regulation of these crude oil gathering pipelines are subject to change based on future determinations by the FERC, federal courts, Congress or by regulatory commissions, courts or legislatures in the states in which the our crude oil gathering pipelines are located. We cannot provide assurance that the 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 the FERC’s jurisdiction. If it was determined that some or all of our gathering pipeline systems are subject to the 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.

Other Crude Oil and Natural Gas Regulation

The State of Colorado is engaged in a number of initiatives that may impact our operations directly or indirectly. To the extent that the State of Colorado adopts new regulations that impact Noble, as our only current customer, the impact of these regulations on Noble production activity may result in decreased demand from Noble for the services we provide.

For example, in 2014, by executive order, Colorado Governor Hickenlooper created the Task Force on State and Local Regulation of Oil and Gas Operations, or the Task Force, for the purpose of recommending policies and legislation aimed at making recommendations for minimizing land use and other conflicts concerning the location of new crude oil and natural gas facilities. The 21-member Task Force, which included a Noble representative, concluded its activities on February 27, 2015. The Task Force sent nine recommendations to Governor Hickenlooper for his review. Three of the proposals require further legislative action, while the other 6 proposals require rulemaking or other regulatory action. The proposals support (i) a senate bill that would postpone expiration of recently adopted regulations regarding air emissions; (ii) tasking the COGCC with crafting new rules related to siting of “large-scale” pads and facilities; (iii) requiring the industry to provide advance information about development plans to local governments; (iv) improving the COGCC’s local government liaison and designee programs; (v) adding 11 full-time staffers to the COGCC to improve inspections and field operations; (vi) bolstering the inspection staff and equipment for monitoring crude oil and natural gas facility air emissions and setting up a hotline for citizen health complaints at the Colorado Department of Public Health and Environment; (vii) creating a statewide crude oil and natural gas information clearinghouse; (viii) studying ways to ameliorate the impact of crude oil and natural gas truck traffic and (ix) creating a compliance-assistance program at the COGCC to help operators comply with the state’s changing rules and ensure consistent enforcement of rules by state inspectors. We may face increased costs of compliance as a result of actions taken in response to these proposals.

Furthermore, in February 2013, the COGCC approved new setback rules for crude oil and natural gas wells and production facilities located in close proximity to occupied buildings. Previously, the COGCC allowed

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setback distances of 150 feet in rural areas and 350 feet in high density urban areas. These have been increased to a uniform 500-foot statewide setback from occupied buildings and 1,000 feet from high occupancy building units. The new setback rules also require operators to utilize increased mitigation measures to limit potential drilling impacts to surface owners and the owners of occupied building units. In addition, the new rules require advance notice to surface owners, the owners of occupied buildings and local governments prior to the filing of an Application for Permit to Drill or Oil and Gas Location Assessment as well as expanded outreach and communication efforts by an operator.

Environmental Matters

General

Our gathering pipelines, crude oil treating facilities and saltwater facilities are subject to certain federal, state and local laws and regulations governing the emission or discharge of materials into the environment or otherwise relating to the protection of the environment.

As an owner or operator of these facilities, we comply with these laws and regulations at the federal, state and local levels. These laws and regulations can restrict or impact our business activities in many ways, such as:

• requiring the acquisition of permits to conduct regulated activities;

• restricting the way we can handle or dispose of our materials or wastes;

• limiting or prohibiting construction and operational activities in sensitive areas such as wetlands, coastal regions or areas inhabited by endangered species;

• requiring remedial action to mitigate pollution conditions caused by our operations or attributable to former operations;

• enjoining, or compelling changes to, the operations of facilities deemed not to be in compliance with permits issued pursuant to such environmental laws and regulations;

• requiring noise, lighting, visual impact, odor or dust mitigation, setbacks, landscaping, fencing and other measures; and

• limiting or restricting water use.

Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements and the issuance of orders enjoining current and future operations. Certain environmental statutes impose strict joint and several liability for costs required to clean up and restore sites where hazardous substances have been disposed or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for property damage or possibly personal injury allegedly caused by the release of substances or other waste products into the environment.

The trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. Thus, there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate. When possible, we attempt to anticipate future regulatory requirements that might be imposed and plan accordingly to manage the costs of such compliance.

Our producers are subject to various environmental laws and regulations, including the ones described below, and could similarly face substantial fines and penalties or other costs resulting from noncompliance with such laws and regulations. Any costs incurred to comply with or fines and penalties imposed related to alleged violations of environmental law that have the potential to impact or curtail production from the producers utilizing our midstream assets could subsequently reduce throughput on our systems and in turn adversely affect our business and results of operations.

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Climate Change and Air Quality Standards

Our operations are subject to the federal Clean Air Act, or CAA, and comparable state and local requirements. The CAA contains provisions that may result in the gradual imposition of certain pollution control requirements with respect to air emissions from our operations. The EPA and states continue the development of regulations to implement these requirements. We may be required to incur certain capital expenditures for air pollution control equipment in connection with maintaining or obtaining preconstruction and operating permits and approvals addressing other air emission-related issues. For example, in February 2015, Colorado’s Air Quality Control Commission approved comprehensive changes to rules governing crude oil and natural gas activities in the state, including the nation’s first-ever regulations designed to detect and reduce methane emissions. The EPA is also acting to increase the requirements associated with methane releases from crude oil and natural gas activities. In 2014, the EPA released a set of five white papers analyzing methane emissions from the industry. As part of the Administration’s efforts to reduce methane emissions from the crude oil and natural gas sector by up to 45% from 2012 levels by 2025, the Obama Administration announced in January 2015 that the EPA is expected to propose in the summer of 2015, and to finalize in 2016, new regulations that will set methane emission standards for new and modified crude oil and natural gas facilities. The BLM is expected to address methane emissions from crude oil and natural gas sources in 2015 as well.

Also, in one other example, in December 2014, the EPA published a proposed regulation that it expects to finalize by October 1, 2015, which rulemaking proposes to lower the National Ambient Air Quality Standard, or NAAQS, for ozone from 75 parts per billion, or ppb, for both the 8-hour primary and secondary standards, to somewhere between 65 and 70 ppb. The proposed revision to the ozone NAAQS is not directly applicable to our operations, but its adoption could require Colorado to enact additional regulations to control emissions of volatile organic compounds and nitrogen oxides from certain sources. Such future regulations could be applicable to our operations and result in increased compliance costs. In addition, the EPA is developing rules to define what are called “source terms” to resolve how sources of emissions from the crude oil and natural gas sector should be aggregated under CAA permit programs. Compliance with these or other new legal requirements could, among other things, require installation of new emission controls on some of our equipment, result in longer permitting timelines, and significantly increase our capital expenditures and operating costs, which could adversely impact our business.

In addition, the EPA, has declared that GHGs “endanger” public health and welfare. Stationary sources required to obtain permits under certain Clean Air Act programs for non-GHG pollutants, particularly the Prevention of Significant Deterioration program and Title V programs, will also be required to review GHG emissions. The EPA has also published various rules relating to the mandatory reporting of GHG emissions, including mandatory reporting requirements of GHGs from petroleum and natural gas systems. The permitting and reporting program taken as a whole increases the costs and complexity of operating crude oil and natural gas operations in compliance with these legal requirements, with resulting potential to adversely affect our cost of doing business, demand for the crude oil and natural gas we transport and may require us to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions.

On June 2, 2015, the U.S. District Court of Colorado entered as a final judgment a Consent Decree between the United States, the State of Colorado and Noble to improve air emission control systems at a number of its condensate storage tanks, and certain of these storage tank systems were transferred to the Partnership and remain subject to such Consent Decree. The Consent Decree requires, in accordance with a set schedule (i) the performance of injunctive relief that will—among other things—evaluate, monitor, verify, and report on the adequate design, operation, and maintenance of certain aspects of tank systems to handle potential peak instantaneous vapor flow rates and (ii) the completion of certain environmental mitigation actions and supplemental environmental projects that may impact certain tank systems and payment of civil penalties.

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Hazardous Substances and Waste

Our operations are subject to environmental laws and regulations relating to the management and release of hazardous substances or solid wastes, including petroleum hydrocarbons. These laws generally regulate the generation, storage, treatment, transportation and disposal of solid and hazardous waste, and may impose strict, joint and several liability for the investigation and remediation of areas at a facility where hazardous substances may have been released or disposed. For instance, the Comprehensive Environmental Response, Compensation and Liability Act, as amended, or 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 contributed to the release of a hazardous substance into the environment. These persons include current and prior owners or operators of the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Under CERCLA, these 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, for damages to natural resources and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. Despite the “petroleum exclusion” of CERCLA Section 101(14) that currently encompasses natural gas, we may nonetheless handle hazardous substances within the meaning of CERCLA, or similar state statutes, in the course of our ordinary operations and, as a result, may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment.

We also generate solid wastes, including hazardous wastes that are subject to the requirements of the Resource Conservation and Recovery Act, as amended, or RCRA, and comparable state statutes. While RCRA regulates both solid and hazardous wastes, it imposes strict requirements on the generation, storage, treatment, transportation and disposal of hazardous wastes. Certain petroleum production wastes are excluded from RCRA’s hazardous waste regulations. However, it is possible that these wastes, which could include wastes currently generated during our operations, will in the future be designated as hazardous wastes and therefore be subject to more rigorous and costly disposal requirements. Any such changes in the laws and regulations could have a material adverse effect on our maintenance capital expenditures and operating expenses.

We currently own or lease properties where petroleum hydrocarbons are being or have been handled for many years. Although we have utilized operating and disposal practices that were standard in the industry at the time, petroleum hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by us or on or under the other locations where these petroleum hydrocarbons and wastes have been taken for treatment or disposal. In addition, certain of these properties have been operated by third parties whose treatment and disposal or release of petroleum hydrocarbons or other wastes was not under our control. These properties and wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater) or to perform remedial operations to prevent future contamination. We are not currently aware of any facts, events or conditions relating to the application of such requirements that could reasonably have a material impact on our operations or financial condition.

Water

The Federal Water Pollution Control Act of 1972, as amended, also referred to as the Clean Water Act, or CWA, and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants into navigable waters. Pursuant to the CWA and analogous state laws, permits must be obtained to discharge pollutants into state and federal waters. Provisions of the CWA require authorization from the U.S. Army Corps of Engineers, or the Corps, prior to the placement of dredge or fill material into jurisdictional waters. On June 29, 2015, the EPA and the Corps published the final rule defining the scope of the EPA’s and Corps’ jurisdiction, known as the “Clean Water Rule.” To the extent the rule expands the scope of the CWA’s jurisdiction, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas.

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The CWA also requires implementation of spill prevention, control and countermeasure plans, also referred to as “SPCC plans,” in connection with on-site storage of threshold quantities of crude oil. In some instances we may also be required to develop a Facility Response Plan that demonstrates our facility’s preparedness to respond to a worst case crude oil discharge. The CWA imposes substantial potential civil and criminal penalties for non-compliance. The EPA has promulgated regulations that require us to have permits in order to discharge certain stormwater. The EPA recently issued a revised general stormwater permit for industrial activities that, among other things, enhances provisions related to threatened endangered species eligibility procedures. The EPA has entered into agreements with certain states in which we operate whereby the permits are issued and administered by the respective states. These permits may require us to monitor and sample the stormwater discharges. State laws for the control of water pollution also provide varying civil and criminal penalties and liabilities. In 2015, Colorado adopted new rules for crude oil and natural gas developments within floodplains and sampling of groundwater for hydrocarbons and other indicators before and after drilling crude oil and natural gas wells. The rule has been challenged in court on the grounds that it unlawfully expands the reach of CWA programs. We believe that compliance with existing permits and compliance with foreseeable new permit requirements will not have a material adverse effect on our financial condition or results of operations.

The Oil Pollution Act of 1990, as amended, or OPA, addresses prevention, containment and cleanup, and liability associated with crude oil pollution. OPA applies to vessels, offshore platforms, and onshore facilities, including terminals, pipelines, and transfer facilities. OPA subjects owners of such facilities to strict liability for containment and removal costs, natural resource damages, and certain other consequences of crude oil spills into jurisdictional waters. Any unpermitted release of petroleum or other pollutants from our operations could result in government penalties and civil liability.

Hydraulic Fracturing

Hydraulic fracturing is a process that creates a fracture extending from a well bore into a low-permeability rock formation to enable crude oil or natural gas to move more easily to a production well. Hydraulic fractures typically are created through the injection of water, sand and chemicals into the rock formation. We do not perform hydraulic fracturing, but our producers do.

Hydraulic fracturing currently is regulated primarily at the state level. Recently, however, several federal agencies have asserted jurisdiction over this process. For example, the Bureau of Land Management finalized rules in March 2015 that impose new requirements related to disclosure, well bore integrity, and water management on hydraulic fracturing on federal lands. The U.S. District Court of Wyoming has temporarily stayed implementation of this rule. A final decision is pending, however. In addition, the EPA issued an Advanced Notice of Proposed Rulemaking under the Toxics Substance Control Act in 2014 requesting comments relating to information that may be required to be reported or disclosed for hydraulic fracturing chemical substances and mixtures. The actions and assessment being undertaken by local, state and federal authorities could result in further legislative and regulatory initiatives. Moreover, the governments of certain states, including Colorado, have adopted or are considering adopting laws and regulations that impose or could impose, among other requirements, stringent permitting or air emission control requirements, disclosure, wastewater disposal, baseline sampling, well construction, plugging and abandonment and well location requirements on hydraulic fracturing operations or otherwise seek to ban underground injection of fracturing wastewater or fracturing activities altogether. At the local level, some municipalities and local governments have adopted or are considering bans on hydraulic fracturing, including towns in Colorado. Finally, lawsuits have been filed by third parties in several states, among them Colorado, alleging contamination of drinking water by hydraulic fracturing. In the event additional legal restrictions are adopted in areas where our producers conduct operations, our producers may incur substantial costs to comply with these requirements, experience delays, and perhaps even be precluded from drilling wells, which in turn could reduce demand for our services and adversely impact our business and results of operations.

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Endangered Species

The Endangered Species Act, or ESA, and analogous state laws restrict activities that may affect listed endangered or threatened species or their habitats. If endangered species are located in areas where we operate, our operations or any work performed related to them could be prohibited or delayed or expensive mitigation may be required. While some of our operations may be located in areas that are designated as habitats for endangered or threatened species, we believe that we are in compliance with the ESA. In addition, as a result of a settlement approved by the U.S. District Court for the District of Columbia on September 9, 2011, the U.S. Fish and Wildlife Service is required to review and consider the listing of numerous species as endangered under the ESA by no later than the completion of the agency’s 2017 fiscal year. Additional listings under the ESA and similar state laws could result in the imposition of restrictions on our operations and consequently have an adverse effect on our business.

National Environmental Policy Act

Our operations on federal lands are subject to the National Environmental Policy Act, or NEPA. Under NEPA, federal agencies, including the Department of Interior must evaluate major agency actions having the potential to significantly impact the environment. This review can entail a detailed evaluation including an Environmental Impact Statement. This process can result in significant delays and may result in additional limitations and costs associated with projects on federal lands.

Employees

The officers of our general partner will manage our operations and activities. All of the employees required to conduct and support our operations will be employed by Noble and be subject to the operational services agreement that we will enter into with our general partner Noble. As of December 31, 2014, Noble employed approximately 87 people who will provide direct support to our operations pursuant to the operational services agreement. Noble considers its relations with its employees to be satisfactory. Please read “Certain Relationships and Related Transactions—Agreements with our Affiliates in Connection with the Transactions—Operational Services Agreement.”

Insurance

Our business is subject to all of the inherent and unplanned operating risks normally associated with the gathering and treating of water, crude oil and natural gas and the distribution and storage of water. Such risks include weather, fire, explosion, pipeline disruptions and mishandling of fluids any of which could result in damage to, or destruction of, gathering and storage facilities and other property, environmental pollution, injury to persons or loss of life. As protection against financial loss resulting from many, but not all of these operating hazards, pursuant to the terms of the omnibus agreement, we will reimburse Noble for maintaining insurance coverage, including certain physical damage, business interruption, employer’s liability, third party liability and worker’s compensation insurance. Our general partner believes this insurance is appropriate and consistent with industry practice. 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. Our insurance coverage may be provided by an affiliate of Noble or may be shared with Noble. To the extent Noble experiences covered losses under the insurance policies, the limit of our coverage for potential losses may be decreased.

Legal Proceedings

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

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MANAGEMENT

Management of Noble Midstream Partners LP

We are managed by the directors and executive officers of our general partner, Noble Midstream GP LLC. Our general partner is not elected by our unitholders and will not be subject to re-election by our unitholders in the future. Noble owns all of the membership interests in our general partner and has the right to appoint the entire board of directors of our general partner, including our independent directors. Our unitholders are not entitled to elect the directors of our general partner’s board of directors or to directly or indirectly participate in our management or operations. Our general partner will be liable, as general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made specifically nonrecourse to it. Whenever possible, we intend to incur indebtedness that is nonrecourse to our general partner.

At the completion of this offering, we expect that our general partner will have five directors, including one director nominee who will become a member of our board of directors prior to or in connection with the listing of our common units on the NYSE. In accordance with the NYSE’s phase-in rules, we will have at least three independent directors within one year following the effective date of the registration statement of which this prospectus forms a part. We expect that our board will determine that             , our director nominee who will become a member of our board of directors prior to or in connection with the listing of our common units on the NYSE, is independent under the independence standards of the NYSE.

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

Neither we nor our subsidiaries have any employees. Our general partner has the sole responsibility for providing the employees and other personnel necessary to conduct our operations. In addition, pursuant to the operational services and secondment agreement that will be entered into at the closing of this offering, certain of Noble’s employees will be seconded to our general partner to provide management, maintenance and operational services with respect to our business under the direction and control of our general partner. All of the employees that conduct our business will be employed or contracted by our general partner and its affiliates, including Noble, but we sometimes refer to these individuals in this prospectus as our employees.

As a publicly traded partnership, we qualify for, and are relying on, certain exemptions from the NYSE’s corporate governance requirements, including:

• the requirement that a majority of the board of directors of our general partner consist of independent directors;

• the requirement that the board of directors of our general partner have a nominating/corporate governance committee that is composed entirely of independent directors; and

• the requirement that the board of directors of our general partner have a compensation committee that is composed entirely of independent directors.

As a result of these exemptions, we do not expect that our general partner’s board of directors will be comprised of a majority of independent directors. Our board of directors does not currently intend to establish a nominating/corporate governance committee or a compensation committee. Accordingly, unitholders will not have the same protections afforded to equityholders of companies that are subject to all of the corporate governance requirements of the NYSE.

We are, however, required to have an audit committee of at least three members, and all of its members are required to meet the independence and experience standards established by the NYSE and the Exchange Act,

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subject to certain transitional relief during the one-year period following the effective date of the registration statement of which this prospectus forms a part. In accordance with the NYSE’s corporate governance standards, we must have at least one independent member on our audit committee who satisfies the independence and experience requirements by the date our common units are listed on the NYSE, at least a majority of independent members within 90 days of the effective date of the registration statement of which this prospectus forms a part and a fully independent audit committee within one year of such effective date.

Committees of the Board of Directors

The board of directors of our general partner will have an audit committee, and may have such other committees (including a conflicts committee) as the board of directors shall determine from time to time.

Audit Committee

We are required to have an audit committee of at least three members, and all of 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 effective date of the registration statement of which this prospectus forms a part. The audit committee of the board of directors of our general partner will assist the board of directors in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and partnership policies and controls. The audit committee will have the sole authority to (1) retain and terminate our independent registered public accounting firm, (2) approve all auditing services and related fees and the terms thereof performed by our independent registered public accounting firm and (3) pre-approve any non-audit services and tax services to be rendered by our independent registered public accounting firm. The audit committee will also be responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm will be given unrestricted access to the audit committee and our management, as necessary. We expect that             will serve as the initial member of the audit committee. We expect that             will satisfy the definition of audit committee financial expert for purposes of the SEC’s rules. Noble will appoint a second member to the audit committee within 90 days of the effective date of the registration statement of which this prospectus forms a part and appoint a third member to the audit committee within one year following such effective date.

Conflicts Committee

The board of directors of our general partner has the ability to establish a conflicts committee under our partnership agreement. If established, at least two members of the board of directors of our general partner will serve on the conflicts committee to review specific matters that may involve conflicts of interest in accordance with the terms of our partnership agreement. The board of directors of our general partner will determine whether to refer a matter to the conflicts committee on a case-by-case basis. The members of our conflicts committee may not be officers or employees of our general partner or directors, officers or employees of its affiliates (including Noble), 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. In addition, the members of our conflicts committee may not own any interest in our general partner or any interest in us or our subsidiaries other than common units or awards under our long-term incentive plan. If our general partner seeks approval from the conflicts committee, then it will be presumed that, in making its decision, the conflicts committee acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership challenging such determination, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Please read “Conflicts of Interest and Duties.”

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Directors and Executive Officers of Noble Midstream GP LLC

Directors are appointed by Noble, the owner of our general partner, and hold office until their successors have been appointed or qualified or until their earlier death, resignation, removal or disqualification. Executive officers are appointed by, and serve at the discretion of, the board of directors. The following table presents information for the directors, director nominee and executive officers of Noble Midstream GP LLC as of July 22, 2015. Our director nominee will become a member of the board of directors of our general partner prior to or in connection with the listing of our common units on the NYSE.

Name	Age		Position with Our General Partner
Christian S. Kendall		48	Chief Executive Officer and Director
Kenneth M. Fisher		53	Chairman of the Board of Directors
Charles J. Rimer		57	Director
Gary W. Willingham		51	Director

Christian S. Kendall was appointed Chief Executive Officer and as a Director of our general partner in July 2015. Mr. Kendall also currently serves as Senior Vice President of Noble, a position he was appointed to in October 2014. He is currently responsible for worldwide onshore and offshore drilling, major projects including midstream infrastructure, supply chain and aviation. He previously served as Vice President, Gulf of Mexico from 2013 and was Gulf of Mexico Business Unit Manager from 2011. He managed Noble’s Eastern Mediterranean business from 2009 and was Israel Country Manager from 2007, roles which encompassed the construction, startup, and operation of Noble’s midstream treating and measurement facilities in Ashdod, Israel. Serving as Operations Manager in Quito, Ecuador from 2004, he was responsible for both Noble’s offshore Amistad Field assets as well as onshore gas processing, measurement, and delivery to a Noble-owned and operated power generation station. Prior to joining Noble, he held various positions at Mobil and ExxonMobil. We believe Mr. Kendall’s familiarity with our midstream assets and his experience in the energy industry provide the board of directors of our general partner with valuable experience.

Kenneth M. Fisher was appointed as Chairman of the board of directors of our general partner in July 2015. Mr. Fisher serves as Executive Vice President and Chief Financial Officer of Noble, which he was elected to in in April 2014, previously serving as Senior Vice President and Chief Financial Officer from November 2009. Before joining Noble, Mr. Fisher served in a number of senior leadership roles at Shell from 2002 to 2009, including as Executive Vice President of Finance for Upstream Americas, Director of Strategy & Business Development for Royal Dutch Shell plc in The Hague, Executive Vice President of Strategy and Portfolio for Global Downstream in London and CFO of Shell Oil Products US responsible for US downstream finance operations including Shell Pipeline Company. Prior to joining Shell in 2002, Mr. Fisher held senior finance positions within business units of General Electric Company. Mr. Fisher currently serves as a director of CONE Midstream Partners LP. We believe Mr. Fisher’s energy industry and financial experience provides the board of directors of our general partner with valuable experience in our financial and accounting matters.

Charles J. Rimer was appointed to the board of directors of our general partner in December 2014. Mr. Rimer currently serves as Senior Vice President of Noble, which he was appointed to in April 2013, and is currently responsible for Noble’s U.S. onshore operations. He previously served as Vice President of Operations Services for Noble from 2012 and managed Noble’s international West Africa, non-operated and new ventures division from 2002. His prior roles encompassed the construction, startup, and operations of Noble’s midstream treating and measurement facilities in West Africa. He also been responsibility for Noble’s worldwide Major Projects Division prior to his current assignment. Prior to joining Noble, he held various positions at ARCO, Vastar and Aspect Resources. We believe Mr. Rimer’s extensive knowledge of the energy industry and our DJ Basin operations will provide the board of directors our general partner with valuable experience.

Gary W. Willingham was appointed to the board of directors of our general partner in December 2014. Mr. Willingham currently serves as Executive Vice President of Operations for Noble, which he was appointed

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to in October 2014, and is currently responsible for Noble’s global development, production and facilities operations, drilling, major projects and supply chain activities. Mr. Willingham previously served as Senior Vice President of Noble’s U.S. onshore operations, which included responsibility for the DJ Basin midstream assets, since April 2013, and prior to that as Vice President of Strategic Planning, Environmental Analysis and Reserves. Prior to joining the Company, he held various engineering and commercial positions at ARCO, Vastar Resources and BP America. We believe Mr. Willingham’s familiarity with Noble’s operations and experience in the energy industry provide the board of directors of our general partner with valuable experience.

Board Leadership Structure

Although the chief executive officer of our general partner currently does not also serve as the chairman of the board, the board of directors of our general partner has no policy with respect to the separation of the offices of chairman of the board of directors and chief executive officer. Instead, that relationship will be defined and governed by the amended and restated limited liability company agreement of our general partner to be entered into in connection with the closing of this offering, which will permit the same person to hold both offices. Directors of the board of directors of our general partner are designated or elected by Noble. Accordingly, unlike holders of common stock in a corporation, our unitholders will have only limited voting rights on matters affecting our business or governance, subject in all cases to any specific unitholder rights contained in our partnership agreement.

Board Role in Risk Oversight

Our corporate governance guidelines will provide that the board of directors of our general partner is responsible for reviewing the process for assessing the major risks facing us and the options for their mitigation. This responsibility will be largely satisfied by our audit committee, which is responsible for reviewing and discussing with management and our independent registered public accounting firm our major risk exposures and the policies management has implemented to monitor such exposures, including our financial risk exposures and risk management policies.

Reimbursement of Expenses

Our partnership agreement requires us to reimburse our general partner for (i) direct and indirect expenses it incurs or payments it makes on our behalf (including salary, bonus, incentive compensation and other amounts paid to any person, including affiliates of our general partner, to perform services for us or our subsidiaries or for our general partner in the discharge of its duties to us and our subsidiaries) and (ii) all other expenses reasonably allocable to us or our subsidiaries or otherwise incurred by our general partner in connection with operating our business (including expenses allocated to our general partner by its affiliates). Our general partner is entitled to determine the expenses that are allocable to us and our subsidiaries. The costs and expenses for which we will reimburse our general partner and its affiliates may 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. We estimate that the total amount of such reimbursed expenses will be approximately $         million for the twelve months ending September 30, 2016. Please read “Cash Distribution Policy and Restrictions on Distributions—Estimated EBITDA and Distributable Cash Flow for the Twelve Months Ending September 30, 2016.” The costs and expenses for which we are required to reimburse our general partner and its affiliates are not subject to any caps or other limits. Please read “Certain Relationships and Related Party Transactions—Distributions and Payments to Our General Partner and Its Affiliates.”

Compensation of Our Officers and Directors

Executive Compensation

We and our general partner were formed in December 2014. Accordingly, our general partner has not accrued any obligations with respect to management incentive or retirement benefits for its directors or executive officers for the 2014 fiscal year or prior periods. Because our general partner’s executive officers are employed

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by Noble, compensation of the executive officers will be set and paid by Noble. Our general partner has not entered into any employment agreements with any of its executive officers. We expect that compensation for our general partner’s executive officers in 2015 will continue to be determined and structured under Noble’s compensation programs. Our general partner’s executive officers, as well as the employees of Noble who provide services to us, may participate in employee benefit plans and arrangements sponsored by Noble, including plans that may be established in the future, and certain of such officers and employees of Noble who provide services to us currently hold grants under Noble’s equity incentive plans and will retain these grants after the completion of this offering.

Compensation of Our Directors

The officers or employees of our general partner or Noble who also serve as directors of our general partner will not receive additional compensation for their service as a director of our general partner. In connection with this offering, directors of our general partner who are not officers or employees of our general partner or Noble, or “non-employee directors,” will receive cash and equity-based compensation for their services as directors. The non-employee director compensation program will consist of the following:

•

•

Non-employee directors will also receive reimbursement for out-of-pocket expenses they incur in connection with attending meetings of the board of directors or its committees. Each director will be indemnified for his or her actions associated with being a director to the fullest extent permitted under Delaware law.

Our Long-Term Incentive Plan

Our general partner intends to adopt the Noble Midstream Partners LP 2015 Long-Term Incentive Plan, or our LTIP, under which our general partner may issue long-term equity based awards to directors, officers and employees of our general partner or its affiliates, or to any consultants, affiliates of our general partner or other individuals who perform services for us. These awards will be intended to compensate the recipients thereof based on the performance of our common units and their continued service during the vesting period, as well as to align their long-term interests with those of our unitholders. We will be responsible for the cost of awards granted under our LTIP and all determinations with respect to awards to be made under our LTIP will be made by the board of directors of our general partner or any committee thereof that may be established for such purpose or by any delegate of the board of directors or such committee, subject to applicable law, which we refer to as the plan administrator. We currently expect that the board of directors of our general partner or a committee thereof will be designated as the plan administrator. The following description reflects the terms that are currently expected to be included in the LTIP.

General

The LTIP will provide for the grant, from time to time at the discretion of the board of directors of our general partner or any delegate thereof, subject to applicable law, of unit awards, restricted units, phantom units, unit options, unit appreciation rights, distribution equivalent rights, profits interest units and other unit-based awards. The purpose of awards under the LTIP is to provide additional incentive compensation to individuals providing services to us, and to align the economic interests of such individuals with the interests of our unitholders. The LTIP will limit the number of units that may be delivered pursuant to vested awards to              common units, subject to proportionate adjustment in the event of unit splits and similar events. Common units subject to awards that are cancelled, forfeited, withheld to satisfy exercise prices or tax withholding obligations or otherwise terminated without delivery of the common units will be available for delivery pursuant to other awards.

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Restricted Units and Phantom Units

A restricted unit is a common unit that is subject to forfeiture. Upon vesting, the forfeiture restrictions lapse and the recipient holds a common unit that is not subject to forfeiture. A phantom unit is a notional unit that entitles the grantee to receive a common unit upon the vesting of the phantom unit or on a deferred basis upon specified future dates or events or, in the discretion of the plan administrator, cash equal to the fair market value of a common unit. The plan administrator of the LTIP may make grants of restricted units and phantom units under the LTIP that contain such terms, consistent with the LTIP, as the plan administrator may determine are appropriate, including the period over which restricted units or phantom units will vest. The plan administrator of the LTIP may, in its discretion, base vesting on the grantee’s completion of a period of service or upon the achievement of specified financial objectives or other criteria or upon a change of control (as defined in the LTIP) or as otherwise described in an award agreement.

Distributions made by us with respect to awards of restricted units may be subject to the same vesting requirements as the restricted units.

Distribution Equivalent Rights

The plan administrator of the LTIP, in its discretion, may also grant distribution equivalent rights, either as standalone awards or in tandem with other awards. Distribution equivalent rights are rights to receive an amount in cash, restricted units or phantom units equal to all or a portion of the cash distributions made on units during the period an award remains outstanding.

Unit Options and Unit Appreciation Rights

The LTIP may also permit the grant of options covering common units. Unit options represent the right to purchase a number of common units at a specified exercise price. Unit appreciation rights represent the right to receive the appreciation in the value of a number of common units over a specified exercise price, either in cash or in common units. Unit options and unit appreciation rights may be granted to such eligible individuals and with such terms as the plan administrator of the LTIP may determine, consistent with the LTIP; however, a unit option or unit appreciation right must have an exercise price equal to at least the fair market value of a common unit on the date of grant.

Unit Awards

Awards covering common units may be granted under the LTIP with such terms and conditions, including restrictions on transferability, as the plan administrator of the LTIP may establish.

Profits Interest Units

Awards granted to grantees who are partners, or granted to grantees in anticipation of the grantee becoming a partner or granted as otherwise determined by the plan administrator, may consist of profits interest units. The plan administrator will determine the applicable vesting dates, conditions to vesting and restrictions on transferability and any other restrictions for profits interest awards.

Other Unit-Based Awards

The LTIP may also permit the grant of “other unit-based awards,” which are awards that, in whole or in part, are valued or based on or related to the value of a common unit. The vesting of another unit-based award may be based on a participant’s continued service, the achievement of performance criteria or other measures. On vesting or on a deferred basis upon specified future dates or events, another unit-based award may be paid in cash or in units (including restricted units) or any combination thereof as the plan administrator of the LTIP may determine.

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Source of Common Units

Common units to be delivered with respect to awards may be newly-issued units, common units acquired by us or our general partner in the open market, common units already owned by our general partner or us, common units acquired by our general partner directly from us or any other person or any combination of the foregoing.

Anti-Dilution Adjustments and Change in Control

If an “equity restructuring” event occurs that could result in an additional compensation expense under applicable accounting standards if adjustments to awards under the LTIP with respect to such event were discretionary, the plan administrator of the LTIP will equitably adjust the number and type of units covered by each outstanding award and the terms and conditions of such award to equitably reflect the restructuring event, and the plan administrator will adjust the number and type of units with respect to which future awards may be granted under the LTIP. With respect to other similar events, including, for example, a combination or exchange of units, a merger or consolidation or an extraordinary distribution of our assets to unitholders, that would not result in an accounting charge if adjustment to awards were discretionary, the plan administrator of the LTIP shall have discretion to adjust awards in the manner it deems appropriate and to make equitable adjustments, if any, with respect to the number of units available under the LTIP and the kind of units or other securities available for grant under the LTIP. Furthermore, upon any such event, including a change in control of us or our general partner, or a change in any law or regulation affecting the LTIP or outstanding awards or any relevant change in accounting principles, the plan administrator of the LTIP will generally have discretion to (i) accelerate the time of exercisability or vesting or payment of an award, (ii) require awards to be surrendered in exchange for a cash payment or substitute other rights or property for the award, (iii) provide for the award to assumed by a successor or one of its affiliates, with appropriate adjustments thereto, (iv) cancel unvested awards without payment or (v) make other adjustments to awards as the plan administrator deems appropriate to reflect the applicable transaction or event.

Termination of Service

The consequences of the termination of a grantee’s membership on the board of directors of our general partner or other service arrangement will generally be determined by the plan administrator in the terms of the relevant award agreement.

Amendment or Termination of Long-Term Incentive Plan

The plan administrator of the LTIP, at its discretion, may terminate the LTIP at any time with respect to the common units for which a grant has not previously been made. The plan administrator of the LTIP also has the right to alter or amend the LTIP or any part of it from time to time or to amend any outstanding award made under the LTIP, provided that no change in any outstanding award may be made that would materially impair the vested rights of the participant without the consent of the affected participant or result in taxation to the participant under Section 409A of the Code.

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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth the beneficial ownership of common units and subordinated units of Noble Midstream Partners LP that will be issued upon the completion of this offering and the related transactions and held by:

• each unitholder known by us to beneficially hold 5% or more of our outstanding units;

• each director or director nominee of our general partner;

• each named executive officer of our general partner; and

• all of the directors, director nominee and named executive officers of our general partner as a group.

In addition, in connection with the completion of this offering, we will issue a non-economic general partner interest and to our general partner and all of the incentive distribution rights to Noble.

Beneficial ownership is determined under the rules of the SEC and generally includes voting or investment power with respect to securities. Unless indicated below, to our knowledge, the persons and entities named in the following table have sole voting and sole investment power with respect to all units beneficially owned by them, subject to community property laws where applicable.

The following table assumes that the underwriters’ option to purchase additional common units is not exercised. The percentage of units beneficially owned is based on a total              common units and              subordinated units outstanding immediately following this offering. The following table does not include any common units that the directors, director nominee and named executive officers of our general partner may purchase in this offering through the directed unit program described under “Underwriting.”

Name of Beneficial Owner(1)	Common Units To Be Beneficially Owned	Percentage of Common Units To Be Beneficially Owned		Subordinated Units To Be Beneficially Owned		Percentage of Subordinated Units To Be Beneficially Owned			Percentage of Total Common Units and Subordinated Units To Be Beneficially Owned
Noble Energy, Inc.			%				100	%		%
Directors/Named Executive Officers
Christian S. Kendall					—		—
Kenneth M. Fisher					—		—
Charles J. Rimer					—		—
Gary W. Willingham					—		—
Director Nominee
					—		—
All Directors, Director Nominee and Executive Officers as a group
(     persons)					—		—

* Less than 1%.

(1) Unless otherwise indicated, the address for all beneficial owners in this table is c/o Noble Midstream GP LLC, 1001 Noble Energy Way, Houston, Texas 77070.

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The following table sets forth, as of                     , 2015, the number of shares of Noble common stock beneficially owned by each of the directors, director nominee and named executive officers of our general partner and all of the directors, director nominee and named executive officers of our general partner as a group. The percentage of total shares is based on              shares outstanding as of                     , 2015. Amounts shown below include options that are currently exercisable or that may become exercisable within 60 days of                     , 2015 and the shares underlying restricted stock awards that will be settled within 60 days of                     , 2015. Unless otherwise indicated, the named person has the sole voting and dispositive powers with respect to the shares of Noble common stock set forth opposite such person’s name.

Name of Beneficial Owner	Total Common Stock Beneficially Owned	Percent of Total Outstanding
Directors/Named Executive Officers
Christian S. Kendall
Kenneth M. Fisher
Charles J. Rimer
Gary W. Willingham
Director Nominee
All Directors, Director Nominee and Executive Officers as a group
(     persons)

* Less than 1%.

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

Following the completion of this offering, Noble will own             common units and             subordinated units, representing an aggregate     % limited partner interest (or             common units and             subordinated units, representing an aggregate     % limited partner interest, if the underwriters exercise in full their option to purchase additional common units). In addition, our general partner will own a non-economic general partner interest in us and Noble will own all of our incentive distribution rights.

Distributions and Payments to Our General Partner and Its Affiliates

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 liquidation of us. These distributions and payments were determined by and among affiliated entities and, consequently, are not the result of arm’s-length negotiations.

Formation/Offering Stage

The consideration received by our general partner and its affiliates, including Noble, prior to or in connection with this offering for the contribution of the controlling interests in our development companies to us •             common units (or             common units if the underwriters exercise in full their option to purchase additional common units);

•             subordinated units;

• a distribution of approximately $         million from the net proceeds of this offering (or $         million if the underwriters exercise in full their option to purchase additional common units);

• the incentive distribution rights; and

• a non-economic general partner interest.

Post-IPO Operational Stage

Distributions of available cash to Noble We will generally make cash distributions to our unitholders pro rata, including Noble, as holder of an aggregate of             common units and             subordinated units. In addition, if distributions exceed the minimum quarterly distribution and target distribution levels, the incentive distribution rights held by Noble will entitle it to increasing percentages of the distributions, up to 50% of the distributions above the highest target distribution level.

Assuming we generate sufficient distributable cash flow to make the payment of the full minimum quarterly distribution on all of our outstanding units for four quarters, Noble would receive an aggregate annual distribution of approximately $         million on its common units and subordinated units (or $         million if the underwriters exercise in full their option to purchase additional common units).

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Payments to our general partner and its affiliates Under our partnership agreement, we are required to reimburse our general partner and its affiliates for all costs and expenses that they incur on our behalf for managing and controlling our business and operations.

Under our operational services and secondment agreements, we will reimburse Noble for the secondment to our general partner of certain employees who serve management, maintenance and operational functions in support of our operations and for the provision of those personnel, including with respect to routine and emergency maintenance and repair services, routine operational activities, routine administrative services and such other services as we and Noble may mutually agree upon from time to time. The costs and expenses for which we will be required to reimburse Noble and its affiliates will not be subject to any caps or other limits. Please read “—Agreements with our Affiliates in Connection with the Transactions—Operational Services Agreement” below and “Management—Compensation of Our Officers and Directors.”

Under our omnibus agreement, we will reimburse Noble for all reasonable direct and indirect costs and expenses incurred by Noble and its affiliates in connection with the provision of for certain general and administrative services, such as treasury, accounting and legal services. These services will be consistent in nature and quality to the services of such type previously provided by Noble in connection with our assets. Please read “—Agreements with our Affiliates in Connection with the Transactions—Omnibus Agreement”

Withdrawal or removal of our general partner If our general partner withdraws or is removed, its non-economic general partner interest will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests. Please read “Our Partnership Agreement—Withdrawal or Removal of Our General Partner.”

Liquidation Stage

Liquidation Upon our liquidation, the partners, including our general partner, will be entitled to receive liquidating distributions according to their respective capital account balances.

Agreements with our Affiliates in Connection with the Transactions

We and other parties will enter into the various agreements that will affect the transactions contemplated by this offering, including the vesting of assets in, and the assumption of liabilities by, us and our subsidiaries, and the application of the proceeds from this offering. While not the result of arm’s-length negotiations, we believe the terms of all of our initial agreements with Noble and its affiliates will be, and specifically intend the rates to be, generally no less favorable to either party than those that could have been negotiated with unaffiliated parties with respect to similar

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services. All of the transaction expenses incurred in connection with these transactions, including the expenses associated with transferring assets into our subsidiaries, will be paid for with the proceeds from this offering.

Omnibus Agreement

At the closing of this offering, we will enter into an omnibus agreement with Noble and our general partner that will address the following matters:

• our payment of an annual operational and administrative support fee, initially in the amount of $         million (prorated for the first year of service), for the provision of certain services by Noble and its affiliates;

• our obligation to reimburse Noble for all other direct or allocated costs and expenses incurred by it in providing general and administrative services (which reimbursement is in addition to certain expenses of our general partner and its affiliates that are reimbursed under the partnership agreement);

• our obligation to reimburse Noble for the provision of certain operations services to us in support of our midstream systems under the operational services agreement;

• our ROFR to acquire (i) Noble’s retained interests in each of our Core Assets and Growth Assets, (ii) Noble’s other ancillary midstream assets that it will retain after the completion of this offering and (iii) any additional midstream assets that Noble retains, acquires or develops in North America not otherwise subject to a third party purchase right;

• our ROFR to provide midstream services on acreage that Noble owns or acquires in North America, including Noble’s newly acquired Eagle Ford shale and Permian Basin acreage; and

• an indemnity by Noble for certain environmental and other liabilities, and our obligation to indemnify Noble for events and conditions associated with the operations of our assets that occur after the closing of this offering and for environmental liabilities related to our assets to the extent Noble is not required to indemnify us.

So long as Noble controls our general partner, the omnibus agreement will remain in full force and effect. If Noble ceases to control our general partner, either party may terminate the omnibus agreement, provided that the indemnification obligations will remain in full force and effect in accordance with their terms.

Payment of operational and administrative support fee and reimbursement of expenses. We will pay Noble an operational and administrative support fee, initially in the amount of $         million (payable in equal monthly installments and prorated for the first year of service), for the provision of certain services for our benefit, including: executive services; financial and administrative services (including treasury and accounting); information technology; legal services; corporate health, safety and environmental services; facility services; human resources services; procurement services; corporate engineering services, including asset integrity and regulatory services; logistical services; asset oversight, such as operational management and supervision; business development services; investor relations; tax matters; and public company reporting services. Noble may increase the operational and administrative support fee on each anniversary of the closing date based on a percentage equal to the greater of zero and the positive change in the PPI provided that if, with respect to any annual period or periods, the PPI has decreased, Noble may increase the operational and administrative support fee only to the extent that the percentage increase in the PPI since the most recent previous increase in the operational and administrative support fee exceeds the cumulative decreases in the PPI during the intervening periods.

Under the omnibus agreement, we will also reimburse Noble for all other direct and allocated costs and expenses incurred by Noble in providing these services to us, including salaries, bonuses and benefits costs, for certain officers of Noble, including those who also serve as officers and directors of our general partner. This reimbursement will be in addition to our reimbursement of our general partner and its affiliates for certain costs and expenses incurred on our behalf for managing and controlling our business and operations as required by our partnership agreement.

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Right of first refusal. Under the omnibus agreement, until the date that Noble no longer controls our general partner, if Noble decides to sell, transfer or otherwise dispose of all or part of (i) Noble’s retained interests in our Core Assets and Growth Assets, (ii) Noble’s other ancillary midstream assets that it will retain after the completion of this offering or (iii) any additional midstream assets that Noble develops or acquires in North America that are not otherwise a third party purchase right, Noble will offer us the opportunity to acquire such interests and assets. In addition, Noble has granted us a ROFR with respect to all midstream services covered by our commercial agreements with Noble on acreage that Noble owns or acquires in North America, including Noble’s newly acquired Eagle Ford Shale and Permian Basin acreage.

The consummation and timing of any acquisition by us of the interests covered by our ROFR will depend upon, among other things, Noble’s decision to sell any of the interests covered by the ROFR and our ability to reach an agreement with Noble on price and other terms. 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 ROFR. Please read “Risk Factors—Risks Related to Our Business—We may be unable to grow by acquiring the non-controlling interests in our development companies owned by Noble or midstream assets retained, acquired or developed by Noble, which could limit our ability to increase our distributable cash flow.”

Indemnification. Under the omnibus agreement, Noble will indemnify us for all known and certain unknown environmental liabilities that are associated with the ownership or operation of our assets and due to occurrences on or before the closing of this offering. Indemnification for any unknown environmental liabilities will be limited to liabilities due to occurrences on or before the closing of this offering and identified prior to the             anniversary of the closing of this offering, and will be subject to a deductible of $         per claim before we are entitled to indemnification. For purposes of calculating the deductible, a “claim” will include all liabilities that arise from a discrete act or event. There is no limit on the amount for which Noble will indemnify us under the omnibus agreement once we meet the deductible, if applicable. Noble will also indemnify us for failure to obtain certain consents, licenses and permits necessary to conduct our business, including the cost of curing any such condition, in each case that are identified prior to the             anniversary of the closing of this offering, and will be subject to an aggregate deductible of $         before we are entitled to indemnification.

Noble will also indemnify us for liabilities relating to:

• the consummation of the transactions contemplated by our contribution agreements or the assets contributed to us, other than environmental liabilities, that arise out of the ownership or operation of the assets prior to the closing of this offering and that are asserted prior to the             anniversary of the closing of this offering;

• events and conditions associated with any assets retained by Noble;

• litigation matters attributable to the ownership or operation of the contributed assets prior to the closing of this offering, which will be subject to an aggregate deductible of $         before we are entitled to indemnification (other than currently pending legal actions, which are not subject to a deductible);

• the failure to have any consent, license, permit or approval necessary for us to own or operate the contributed assets in substantially the same manner as owned or operated by Noble prior to this offering; and

• all tax liabilities attributable to the assets contributed to us arising prior to the closing of this offering or otherwise related to Noble’s contribution of those assets to us in connection with this offering.

We have agreed to indemnify Noble for events and conditions associated with the ownership or operation of our assets that occur after the closing of this offering and for environmental liabilities related to our assets to the extent Noble is not required to indemnify us as described above. There is no limit on the amount for which we will indemnify Noble under the omnibus agreement.

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Operational Services Agreement

Our general partner will enter into an operational services agreement with Noble setting forth the operational services arrangements described below. Noble will second certain employees to our general partner to provide management, maintenance and operational functions with respect to our operations. These functions will include certain operational services to us in support of our gathering pipelines, central gathering facilities and crude oil treating facilities, including routine and emergency maintenance and repair services, routine operational activities, routine administrative services, construction and related services and such other services as we and Noble may mutually agree upon from time to time. During their period of secondment to our general partner, the seconded personnel will be under the direct management and supervision of our general partner. Noble will prepare and submit for our approval a maintenance, operating and capital budget on an annual basis. Noble will submit actual expenditures for reimbursement on a monthly basis and we will reimburse Noble for any direct third-party costs actually incurred by Noble in providing these services.

The operational services agreement will have an initial term of          years and will continue in full force and effect thereafter unless terminated by either party at the end of the initial term or any time thereafter by giving not less than six months’ prior notice to the other party of such termination. Noble may terminate the operational services agreement if (1) we become insolvent, declare bankruptcy or take any action in furtherance of, or indicating our consent to, approval of, or acquiescence in, a similar proceeding or (2) Noble owns less than a     % membership interest in our general partner. We may immediately terminate the agreement (1) if Noble becomes insolvent, declares bankruptcy or takes any action in furtherance of, or indicating its consent to, approval of, or acquiescence in, a similar proceeding or (2) upon a finding of Noble’s gross negligence that has had a material adverse effect on any of our gathering pipelines, centralized gathering facilities and crude oil treating facilities or our business. Either party may terminate the operational services agreement upon 60 days’ written notice if the other party is in material default under the agreement and such party fails to cure the material default within 30 days.

Under the operational services agreement, Noble will indemnify us from any claims, losses or liabilities incurred by us, including third-party claims, arising from Noble’s performance of the agreement to the extent caused by Noble’s gross negligence or willful misconduct. We will indemnify Noble from any claims, losses or liabilities incurred by Noble, including any third-party claims, arising from Noble’s performance of the agreement, except to the extent such claims, losses or liabilities are caused by Noble’s gross negligence or willful misconduct.

Commercial Agreements

At the closing of this offering, we will enter into long-term agreements with Noble for the provision of midstream services. For more information about our operational agreements with Noble, please read “Business—Our Commercial Agreements with Noble—How We Generate Revenue.”

Contribution Agreement

At the closing of this offering, we will enter into a contribution, conveyance and assumption agreement, which we refer to as our contribution agreement, with Noble and our general partner under which Noble will contribute to us a varying controlling interests in the development companies that owns our Core Assets and Growth Assets. More specifically, we will obtain controlling interests in the development companies that owns our Core Assets and Growth Assets as follows:

Noble Midstream Operating LLC, a Delaware limited liability company, or Operating, owns 100% of the membership interests in each of NBLX DevCo I GP LLC, a Delaware limited liability company, or DevCo I GP, NBLX DevCo II GP LLC, a Delaware limited liability company, or DevCo II GP, NBLX DevCo III GP LLC, a Delaware limited liability company, or DevCo III GP, NBLX DevCo IV GP LLC, a Delaware limited liability company, or DevCo IV GP and NBLX DevCo V GP LLC, a Delaware limited liability company, or DevCo V GP and, together with DevCo I GP, DevCo II GP, DevCo III GP and DevCo IV GP, the DevCo General Partners.

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DevCo I GP is the sole general partner of NBLX DevCo I LP, a Delaware limited partnership, or DevCo I LP, and owns a     % general partner interest in DevCo I LP. DevCo II GP is the sole general partner of NBLX DevCo II LP, a Delaware limited partnership, or DevCo II LP, and owns a     % general partner interest in DevCo II LP. DevCo III GP is the sole general partner of NBLX DevCo III LP, a Delaware limited partnership, or DevCo III LP, and owns a     % general partner interest in DevCo III LP. DevCo IV GP is the sole general partner of NBLX DevCo IV LP, a Delaware limited partnership, or DevCo IV LP, and owns a     % general partner interest in DevCo IV LP. DevCo V GP is the sole general partner of NBLX DevCo V LP, a Delaware limited partnership, or DevCo V LP and, together with DevCo I LP, DevCo II LP, DevCo III LP and DevCo IV LP, the DevCo Limited Partnerships, and owns a     % general partner interest in DevCo V LP. Noble owns a     % limited partner interest in DevCo I LP, a     % limited partner interest in DevCo II LP, a     % limited partner interest in DevCo III LP, a     % limited partner interest in DevCo IV LP and a     % limited partner interest in DevCo V LP.

Pursuant to the partnership agreement of each DevCo Limited Partnership, the general partner interest held by the applicable DevCo General Partner (and, ultimately, us through our direct control of Operating and indirect control of the applicable DevCo General Partner upon the completion of this offering) entitles such DevCo General Partner to voting control over, and the exclusive right to manage, the day-to-day operations, business and affairs of the applicable DevCo Limited Partnership. Although the limited partner interest in each DevCo Limited Partnership provides the holder (currently, Noble) economic rights to profits, losses, gains, deductions and credits in proportion to such holder’s percentage interest in the applicable DevCo Limited Partnership, the limited partner interests in each DevCo Limited Partnership do not entitle the holder to any rights with respect to controlling and managing the day-to-day operations, business and affairs of the applicable DevCo Limited Partnership or the ability to remove the general partner.

Prior to the completion of this offering, Noble will contribute 100% of the assets shown on the table under “Business—Our Existing Assets—Growth Assets” to the applicable DevCo Limited Partnerships shown in that table. In connection with the closing of this offering, Noble will contribute to us 100% of the membership interests in Operating pursuant to the contribution agreement. As a result, after the closing of this offering, we will (a) directly own 100% of the membership interests in Operating, (b) indirectly own (through our ownership interest in Operating) 100% of the membership interests in each of the DevCo General Partners, (c) indirectly own (through our indirect ownership interest in DevCo I GP) a     % general partner interest in DevCo I LP, (d) indirectly own (through our indirect ownership interest in DevCo II GP) a     % general partner interest in DevCo II LP, (e) indirectly own (through our indirect ownership interest in DevCo III GP) a     % general partner interest in DevCo III LP, (f) indirectly own (through our indirect ownership interest in DevCo IV GP) a     % general partner interest in DevCo IV LP and (g) indirectly own (through our indirect ownership interest in DevCo V GP) a     % general partner interest in DevCo V LP. Furthermore, through our direct control of Operating and indirect control of the DevCo General Partners, we will control and manage the day to day operations, business and affairs of the DevCo Limited Partnerships. Please read “Business—Our Existing Assets” and “Prospectus Summary—Ownership and Organizational Structure.”

Procedures for Review, Approval and Ratification of Related Person Transactions

The board of directors of our general partner will adopt a code of business conduct and ethics in connection with the completion of this offering that will provide that the board of directors of our general partner or its authorized committee will review on at least a quarterly basis all transactions with related persons that are required to be disclosed under SEC rules and, when appropriate, initially authorize or ratify all such transactions. If the board of directors of our general partner or its authorized committee considers ratification of a transaction with a related person and determines not to so ratify, then the code of business conduct and ethics will provide that our management will make all reasonable efforts to cancel or annul the transaction.

The code of business conduct and ethics will provide that, in determining whether or not to recommend the initial approval or ratification of a transaction with a related person, the board of directors of our general partner or its authorized committee should consider all of the relevant facts and circumstances available, including (if

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applicable) but not limited to: (i) whether there is an appropriate business justification for the transaction; (ii) the benefits that accrue to us as a result of the transaction; (iii) the terms available to unrelated third parties entering into similar transactions; (iv) the impact of the transaction on a director’s independence (in the event the related person is a director, an immediate family member of a director or an entity in which a director or an immediate family member of a director is a partner, shareholder, member or executive officer); (v) the availability of other sources for comparable products or services; (vi) whether it is a single transaction or a series of ongoing, related transactions; and (vii) whether entering into the transaction would be consistent with the code of business conduct and ethics.

The code of business conduct and ethics described above will be adopted in connection with the completion of this offering and, therefore, the transactions described above were not reviewed under such policy.

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CONFLICTS OF INTEREST AND DUTIES

Conflicts of Interest

Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its affiliates, including Noble, on the one hand, and us and our unaffiliated limited partners, on the other hand. The directors and executive officers of our general partner have duties to manage our general partner in a manner that is in the best interests of its owners. At the same time, our general partner has a duty to manage us in a manner that is in the best interests of our partnership.

Whenever a conflict of interest arises between our general partner or its affiliates, on the one hand, and us or any other partner, on the other hand, our general partner will resolve that conflict. Our general partner may seek the approval of such resolution from the conflicts committee of the board of directors of our general partner, or special approval, or from our unitholders, or unitholder approval, but our general partner is not required to do so. There is no requirement under our partnership agreement that our general partner seek special approval or unitholder approval for the resolution of any conflict of interest, and, under our partnership agreement, our general partner may decide to seek such approval or resolve a conflict of interest in any other way permitted by our partnership agreement, as described below, in its sole discretion. The board of directors of our general partner will decide whether to refer a matter to the conflicts committee or to our unitholders on a case-by-case basis. In determining whether to refer a matter to the conflicts committee or to our unitholders for approval, the board of directors of our general partner will consider a variety of factors, including the nature of the conflict, the size of the transaction and dollar amount involved, the identity of the parties involved and any other factors the board of directors deems relevant in determining whether it will seek special approval or unitholder approval. Whenever our general partner makes a determination to seek special approval, to seek unitholder approval or to adopt a resolution or course of action that has not received special approval or unitholder approval, then our general partner will be entitled, to the fullest extent permitted by law, to make such determination free of any duty or obligation whatsoever to our partnership or any limited partner, and our general partner will not, to the fullest extent permitted by law, be required to act in good faith or pursuant to any other standard or duty imposed by our partnership agreement or under the Delaware Act or any other law, rule or regulation or at equity, and our general partner in making such determination will be permitted to do so in its sole and absolute discretion. For a more detailed discussion of the duties applicable to our general partner, please read “—Duties of Our General Partner.”

Whenever a potential conflict of interest exists or arises, any resolution or course of action by our general partner or its affiliates in respect of such conflict of interest will be permitted and deemed approved by all partners, and will not constitute a breach of our partnership agreement or of any duty stated or implied by law or equity, if the resolution or course of action in respect of such conflict of interest is:

• approved by special approval, which our partnership agreement defines as approval by a majority of the members of the conflicts committee; or

• approved by unitholder approval, which our partnership agreement defines as the vote of a majority of the outstanding common units, excluding any common units owned by our general partner or any of its affiliates.

If our general partner seeks special approval from the conflicts committee, then it will be presumed that, in making its decision, the conflicts committee acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership challenging such determination, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. If our general partner does not seek special approval or unitholder approval, then our general partner, the board of directors of our general partner or any committee of the board of directors of our general partner (including the conflicts committee), as applicable, will make such determination or take or decline to take any action in good faith, and none of our general partner, the board of directors of our general partner or any committee of the board of directors of our general partner (including the conflicts committee), as applicable, will be subject to any fiduciary duty or other duty or

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obligation, or any other, different or higher standard under our partnership agreement or under the Delaware Act or any other law, rule or regulation or at equity. Under our partnership agreement, it will be presumed that, in making its decision, our general partner, the board of directors of our general partner or any committee of the board of directors of our general partner (including the conflicts committee), as applicable, acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership challenging such determination, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Unless the resolution of a conflict is specifically provided for in our partnership agreement, our general partner or the conflicts committee of our general partner’s board of directors may consider any factors it determines in good faith to consider when resolving a conflict. In order for a determination or the taking or declining to take an action to be in “good faith” for purposes of our partnership agreement, the person or persons making such determination or taking or declining to take such action must subjectively believe that the determination or other action is in the best interests of the partnership. In taking such action, such person may take into account the totality of the circumstances or the totality of the relationships between the parties involved, including other relationships or transactions that may be particularly favorable or advantageous to us. If that person has the required subjective belief, then the decision or action will be conclusively deemed to be in good faith for all purposes under our partnership agreement.

It is possible, but we believe it is unlikely, that our general partner would approve a matter that the conflicts committee has previously declined to approve or declined to recommend that the full board of directors approve. If the conflicts committee does not approve or does not recommend that the full board of directors approve a matter that has been presented to it, then, unless the board of directors of our general partner has delegated exclusive authority to the conflicts committee, the board of directors of our general partner may subsequently approve the matter. In such a case, although the matter will not have received “special approval” under our partnership agreement, the board of directors of our general partner could still determine to resolve the conflict of interest solely under the good faith standard. In making any such determination, the board of directors of our general partner may take into account the totality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous to us. 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.

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

Affiliates of our general partner, including Noble, 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 dedications contained in our commercial agreements and rights of first refusal contained in our omnibus agreement.

Our partnership agreement provides that our general partner will be restricted from engaging in any business activities other than acting as our general partner (or as general partner or managing member of another entity of which we are a partner or member) or those activities incidental to its ownership of interests in us. However, affiliates of our general partner, including Noble, are not prohibited from engaging in other businesses or activities, including those that might compete with us.

Neither our partnership agreement nor our omnibus agreement will prohibit Noble 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 Noble 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. 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, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. Consequently, Noble and other affiliates of our general partner may acquire,

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construct or dispose of additional midstream assets in the future without any obligation under our partnership agreement to offer us the opportunity to purchase any of those assets. As a result, competition from Noble and other affiliates of our general partner could materially and adversely impact our results of operations and distributable cash flow.

Our general partner is allowed to take into account the interests of parties other than us, such as Noble, in resolving conflicts of interest.

Our partnership agreement contains provisions that reduce and modify 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, free of any duty or obligation to us and our unitholders. This entitles our general partner to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us or any limited partner. Examples of decisions that our general partner may make in its individual capacity include: (i) how to allocate business opportunities among us and affiliates of our general partner; (ii) whether to exercise its limited call right; (iii) how to exercise its voting rights with respect to any units it owns; (iv) whether to exercise its registration rights; (v) whether to sell or otherwise dispose of units or other partnership interests that it owns; (vi) whether to elect to reset target distribution levels; (vii) whether to consent to any merger, consolidation or conversion of the partnership or amendment to our partnership agreement; and (viii) whether to refer or not to refer any potential conflict of interest to the conflicts committee for special approval or to seek or not to seek unitholder approval.

Our partnership agreement replaces the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing its duties and limits our general partner’s liabilities and the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty under applicable Delaware law.

In addition to the provisions described above, our partnership agreement contains provisions that restrict the remedies available to our limited partners for actions that might constitute breaches of fiduciary duty under applicable Delaware 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. When acting in its individual capacity, our general partner is entitled 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 or any limited partner;

• provides that the general partner will have no liability to us or our limited partners for decisions made in its capacity as a general partner so long as such decisions are made in good faith reliance on the provisions of our partnership agreement;

• generally provides that in a situation involving a transaction with an affiliate or other conflict of interest, any determination by our general partner must be made in good faith. If an affiliate transaction or the resolution of another conflict of interest does not receive special approval or unitholder approval, then our general partner will make such determination or take or decline to take any action in good faith, and neither our general partner nor the board of directors of our general partner will be subject to any fiduciary duty or other duty or obligation, or any other, different or higher standard under our partnership agreement or under the Delaware Act or any other law, rule or regulation or at equity. Under our partnership agreement, it will be presumed that in making its decision, our general partner (including the board of directors of our general partner) acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us challenging such decision, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption; and

• provides that our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners resulting from any act or omission unless there has been a final and non-

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appealable judgment entered by a court of competent jurisdiction determining that our general partner or its officers or directors, as the cases may be, acted in bad faith or engaged in actual fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was unlawful.

By purchasing a common unit, a common unitholder will be deemed to have agreed to become bound by the provisions in our partnership agreement, including the provisions discussed above.

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, on such terms as it determines to be necessary or appropriate to conduct our business, including, but not limited to, the following:

• the making of any expenditures, the lending or borrowing of money, the assumption or guarantee of or other contracting for, indebtedness and other liabilities, the issuance of evidences of indebtedness, including indebtedness that is convertible into our securities, and the incurring of any other obligations;

• the purchase, sale or other acquisition or disposition of our securities, or the issuance of additional options, rights, warrants and appreciation rights relating to our securities;

• the acquisition, disposition, mortgage, pledge, encumbrance, hypothecation or exchange of any or all of our assets (though subject to any prior approval required under our partnership agreement);

• the negotiation, execution and performance of any contracts, conveyances or other instruments;

• the distribution of our cash;

• the selection and dismissal of employees (including officers) and agents, outside attorneys, accountants, consultants and contractors and the determination of their compensation and other terms of employment or hiring;

• the maintenance of insurance for our benefit and the benefit of our partners;

• the formation of, or acquisition of an interest in, the contribution of property to, and the making of loans to, any limited or general partnership, joint venture, corporation, limited liability company or other entity;

• the control of any matters affecting our rights and obligations, including the bringing and defending of actions at law or in equity, otherwise engaging in the conduct of litigation, arbitration or mediation and the incurring of legal expense, the settlement of claims and litigation;

• the indemnification of any person against liabilities and contingencies to the extent permitted by law;

• the making of tax, regulatory and other filings, or the rendering of periodic or other reports to governmental or other agencies having jurisdiction over our business or assets; and

• the entering into of agreements with any of its affiliates to render services to us or to itself in the discharge of its duties as our general partner.

Our partnership agreement provides that our general partner must act in good faith when making decisions on our behalf in its capacity as our general partner, and our partnership agreement further provides that in order for a determination to be made in good faith, our general partner must subjectively believe that the determination is in the best interests of our partnership. In making such determination, our general partner may take into account the totality of the circumstances or the totality of the relationships between the parties involved, including other relationships or transactions that may be particularly favorable or advantageous to us. When our general partner is acting in its individual capacity, as opposed to in its capacity as our general partner, it may act free of any duty or obligation to us or our limited partners. Please read “Our Partnership Agreement—Voting Rights” for information regarding matters that require unitholder approval.

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Actions taken by our general partner may affect the amount of cash available for distribution to unitholders or accelerate the right to convert subordinated units.

The amount of cash that is available for distribution to unitholders is affected by decisions of our general partner regarding matters such as the amount and timing of:

• cash expenditures;

• borrowings and repayments of indebtedness;

• the issuance of additional partnership interests;

• the creation, increase or reduction in cash reserves in any quarter; and

• asset purchases and sales.

Our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus. This determination can affect the amount of cash that is distributed to our unitholders, the amount of adjusted operating surplus generated in any given period and the ability of the subordinated units to convert into common units. 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 “Provisions of Our Partnership Agreement Relating to Cash Distributions.”

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:

• enabling our Noble or its affiliates to receive distributions on any subordinated units or the incentive distribution rights held by them; or

• accelerating the expiration of the subordination period.

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 working capital funds, which would enable us to make this distribution on all outstanding units. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions—Subordinated Units and Subordination Period.”

Our partnership agreement provides that we and our subsidiaries may borrow funds from our general partner and its affiliates. Our general partner and its affiliates may not borrow funds from us or our operating subsidiaries.

We will reimburse our general partner and its affiliates for expenses.

We will reimburse our general partner and its affiliates, including Noble, for costs incurred in managing and operating us. Our partnership agreement provides that our general partner will determine the expenses that are allocable to us in good faith, and it will charge on a fully allocated cost basis for services provided to us. Our omnibus agreement and operational services agreement will also address our payment of annual amounts to, and our reimbursement of, our general partner and its affiliates for these costs and services. Please read “Certain Relationships and Related Party Transactions.”

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

Our partnership agreement allows our general partner to determine, in good faith, any amounts to pay itself or its affiliates for any services rendered to us. Our general partner may also enter into additional contractual

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arrangements with any of its affiliates on our behalf. Our general partner will determine, in good faith, the terms of any arrangements or transactions entered into after the completion of this offering. While 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, we believe the terms of all of our initial agreements with our general partner and its affiliates will be, and specifically intend the fees to be, generally no less favorable to either party than those that could have been negotiated with unaffiliated parties with respect to similar services. Similarly, agreements, contracts or arrangements between us and our general partner and its affiliates that are entered into following the completion of this offering will not be required to be negotiated on an arm’s-length basis, although, in some circumstances, our general partner may determine that the conflicts committee may make a determination on our behalf with respect to such arrangements.

As we have historically derived, and expect to initially derive, substantially all of our revenue from our commercial agreements with Noble, any event, whether in our dedicated acreage or elsewhere, that materially and adversely affects Noble’s business strategies with respect to drilling on and development of our dedicated acreage or their financial condition, results of operations or cash flows may adversely affect our ability to sustain or increase cash distributions to our unitholders. Further, we have no control over Noble’s business decisions and operations, and Noble is under no obligation to adopt a business strategy that is favorable to us. Thus, we are subject to the risk of non-payment or non-performance by Noble, including with respect to our commercial agreements. We cannot predict the extent to which Noble’s businesses would be impacted if conditions in the energy industry were to deteriorate nor can we estimate the impact such conditions would have on Noble’s decisions with respect to drilling and development on our dedicated acreage or performance under our commercial agreements. In addition, our general partner and its affiliates, including Noble, may have specific conflicts of interest with respect to the rights of Noble under our commercial agreements. For example, if we fail to timely complete the construction of the facilities necessary to provide midstream services to Noble’s production on our dedicated acreage, Noble has the right to permanently release the affected acreage from our dedication. Noble is under no obligation to restrict its ability to exercise this (and other) rights under our commercial agreements that may not yield a favorable result for us, and we are subject to the risk that they will exercise these rights for any number of reasons. Please read “Business—Our Commercial Agreements with Noble.”

Our general partner and its affiliates will have no obligation to permit us to use any facilities or assets of our general partner and its affiliates, except as may be provided in contracts entered into specifically for such use. There is no obligation of our general partner and its affiliates to enter into any contracts of this kind.

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

Our general partner intends to limit its liability under contractual arrangements and other obligations so that counterparties to such agreements have recourse only against our assets and not against our general partner or its assets or any affiliate of our general partner or its assets. 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 fiduciary duties, even if we could have obtained terms that are more favorable without the limitation on liability.

Common units are subject to our general partner’s limited call right.

Our general partner may exercise its right to call and purchase common units, as provided in our partnership agreement, or may assign this right to one of its affiliates or to us. Our general partner may use its own discretion, free of any duty or liability to us or our unitholders, in determining whether to exercise this right. As a result, a common unitholder may have to sell its common units at an undesirable time or at a price that is less than the market price on the date of purchase. Please read “Our Partnership Agreement—Limited Call Right.”

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Common unitholders will 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 hand, 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.

Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

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 our conflicts committee and may perform services for our general partner and its affiliates. We may retain separate counsel for ourselves or the holders of common units 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 hand, depending on the nature of the conflict. We do not intend to do so in most cases.

Noble may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to its incentive distribution rights without the approval of our conflicts committee or our unitholders. This election may result in lower distributions to our common unitholders in certain situations.

Noble, as the initial holder of our incentive distribution rights, has the right, 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 each of the prior four consecutive calendar quarters, to reset the initial target distribution levels at higher levels based on our cash distribution level at the time of the exercise of the reset election. Furthermore, Noble has the right to transfer all or any portion of the incentive distribution rights at any time, and such transferee shall have the same rights as our Noble relative to resetting target distributions if our general partner concurs that the tests for resetting target distributions have been fulfilled. Following a reset election by Noble, the minimum quarterly distribution will be reset to an amount equal to the average cash distribution per unit for the two calendar quarters 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 Noble 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; however, it is possible that Noble could exercise this reset election at a time when we are experiencing declines in our aggregate cash distributions or at a time when Noble expects that we will experience declines in our aggregate cash distributions in the foreseeable future. In such situations, Noble may be experiencing, or may expect to experience, declines in the cash distributions it receives related to its incentive distribution rights and may therefore desire to be issued common units, which are entitled to specified priorities with respect to our distributions and which therefore may be more advantageous for the general partner to own in lieu of the right to receive incentive distribution payments based on target distribution levels that are less certain to be achieved in the then current business environment. 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 common units to Noble in connection with resetting the target distribution levels related to Noble’s incentive distribution rights. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions—Incentive Distribution Rights.”

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Duties of Our General Partner

Delaware law provides that a Delaware limited partnership may, in its partnership agreement, expand, restrict or eliminate the fiduciary duties otherwise owed by the general partner to limited partners and the partnership, provided that the partnership agreement may not eliminate the implied contractual covenant of good faith and fair dealing. This implied covenant is a judicial doctrine utilized by Delaware courts in connection with interpreting ambiguities in partnership agreements and other contracts, and does not form the basis of any separate or independent fiduciary duty in addition to the express contractual duties set forth in our partnership agreement. Under the implied contractual covenant of good faith and fair dealing, a court will enforce the reasonable expectations of the partners where the language in the partnership agreement does not provide for a clear course of action.

As permitted by the Delaware Act, our partnership agreement contains various provisions replacing the fiduciary duties that might otherwise be owed by our general partner with contractual standards governing the duties of our general partner and contractual methods of resolving conflicts of interest. We have adopted these provisions to allow our general partner or its affiliates to engage in transactions with us that would otherwise 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 duties to manage our general partner in a manner that is in the best interests of its owners in addition to the best interests of our partnership. Without these provisions, our general partner’s ability to make decisions involving conflicts of interest would be restricted. These provisions enable our general partner to take into consideration the interests of all parties involved in the proposed action. These provisions also strengthen the ability of our general partner to attract and retain experienced and capable directors. These provisions disadvantage the common unitholders because they restrict the rights and remedies that would otherwise be available to such unitholders for actions that, without those limitations, might constitute breaches of fiduciary duty, as described below, and permit our general partner to take into account the interests of third parties in addition to our interests when resolving conflicts 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 laws on our general partner and the rights and remedies of our unitholders with respect to these contractual duties:

State law fiduciary duty standards Fiduciary duties are generally considered to include an obligation to act in good faith and with due care and loyalty. The duty of care, in the absence of a provision in a partnership agreement providing otherwise, would generally require a general partner to act for the partnership in the same manner as a prudent person would act on his own behalf. The duty of loyalty, in the absence of a provision in a partnership agreement providing otherwise, would generally prohibit a general partner of a Delaware limited partnership from taking any action or engaging in any transaction where a conflict of interest is present unless such transactions were entirely fair to the partnership.

Partnership agreement modified standards Our partnership agreement contains provisions that waive or consent to conduct by our general partner and its affiliates that might otherwise raise issues as to compliance with fiduciary duties or applicable law. For example, our partnership agreement provides that when our general partner is acting in its capacity as our general partner, as opposed to in its individual capacity, it must act in good faith, meaning that it subjectively believed that the decision was in the best interests of our partnership, and our general partner will not be subject to any other standard under our partnership agreement or

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applicable law, other than the implied contractual covenant of good faith and fair dealing. If our general partner has the required subjective belief, then the decision or action will be conclusively deemed to be in good faith for all purposes under our partnership agreement. In taking such action, our general partner may take into account the totality of the circumstances or the totality of the relationships between the parties involved, including other relationships or transactions that may be particularly favorable or advantageous to us. In addition, when our general partner is acting in its individual capacity, as opposed to in its capacity as our general partner, it may act free of any duty or obligation to us or our limited partners. These standards reduce the obligations to which our general partner would otherwise be held. If our general partner seeks special approval from the conflicts committee, then it will be presumed that, in making its decision, the conflicts committee acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership challenging such determination, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. If our general partner does not seek special approval from our conflicts committee or unitholder approval, then our general partner will make such determination or take or decline to take any action in good faith, and neither our general partner nor the board of directors of our general partner will be subject to any fiduciary duty or other duty or obligation, or any other, different or higher standard under our partnership agreement or under the Delaware Act or any other law, rule or regulation or at equity. Under our partnership agreement, it will be presumed that, in making its decision, our general partner (including the board of directors of our general partner) acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us challenging such approval, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. These standards reduce the obligations to which our general partner would otherwise be held.

In addition to the other more specific provisions limiting the obligations of our general partner, our partnership agreement further provides that our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners for errors of judgment or for any acts or omissions unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that our general partner or its officers and directors acted in bad faith or engaged in actual fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was unlawful.

Rights and remedies of unitholders The Delaware Act generally provides that a limited partner may institute legal action on behalf of the partnership to recover damages from a third party where a general partner has refused to institute the action or where an effort to cause a general partner to do so is not likely to succeed. These actions include actions against a general partner for breach of its fiduciary duties, if any, or of the partnership agreement.

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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 a 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 and managers, 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 these persons acted in bad faith or engaged in actual fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was unlawful. We also must provide this indemnification for criminal proceedings when our general partner or these other persons acted with no knowledge that their conduct was unlawful. Thus, our general partner could be indemnified for its negligent acts if it met the requirements set forth above. To the extent that these provisions purport to include indemnification for liabilities arising under the Securities Act of 1933, as amended, or the Securities Act, in the opinion of the SEC, such indemnification is contrary to public policy and therefore unenforceable. Please read “Our Partnership Agreement—Indemnification.”

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DESCRIPTION OF OUR COMMON UNITS

Our Common Units

Our common units represent limited partner interests in us. The holders of common units, along with the holders of subordinated units, are entitled to participate in partnership distributions and to exercise the rights and privileges provided to limited partners under our partnership agreement. Please read “Cash Distribution Policy and Restrictions on Distributions” and “Provisions of Our Partnership Agreement Relating to Cash Distributions.” For a description of the rights and privileges of limited partners under our partnership agreement, including voting rights, please read “Our Partnership Agreement.”

Transfer Agent and Registrar

Duties

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

• surety bond premiums to replace lost or stolen certificates, or to cover taxes and other governmental charges in connection therewith;

• special charges for services requested by a holder of a common unit; and

• other similar fees or charges.

Unless our general partner determines otherwise in respect of some or all of any classes of our partnership interests, our partnership interests will be evidenced by book-entry notation on our partnership register and not by physical certificates.

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 respective 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.

Resignation or Removal

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 a successor has not been appointed or has not accepted its appointment within 30 days after notice of the resignation or removal, our general partner may act as the transfer agent and registrar until a successor is appointed.

Transfer of Common Units

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. Each transferee:

• represents that the transferee has the capacity, power and authority to become bound by our partnership agreement;

• automatically agrees to be bound by the terms and conditions of, and is deemed to have executed, our partnership agreement; and

• gives the consents and approvals contained in our partnership agreement, such as the approval of all transactions and agreements entered into in connection with our formation and this offering.

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A transferee will become a substituted limited partner of our partnership for the transferred common units automatically upon the recording of the transfer on our books and records. Our general partner will cause any transfers to be recorded on our books and records from time to time as necessary to accurately reflect the transfers but no less frequently than quarterly.

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 are transferable according 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 securities exchange regulations.

Exchange Listing

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

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OUR PARTNERSHIP AGREEMENT

The following is a summary of the material provisions of our partnership agreement. The form of our partnership agreement is included in this prospectus as Appendix A. We will provide prospective investors with a copy of our partnership agreement upon request at no charge.

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

• with regard to distributions of available cash, please read “Provisions of Our Partnership Agreement Relating to Cash Distributions”;

• with regard to the duties of our general partner, please read “Conflicts of Interest and Duties”;

• with regard to the authority of our general partner to manage our business and activities, please read “Management”;

• with regard to the transfer of common units, please read “Description of Our Common Units—Transfer of Common Units”; and

• with regard to allocations of taxable income and taxable loss, please read “Material Federal Income Tax Consequences.”

Organization and Duration

Our partnership was organized on December 23, 2014 and will have a perpetual existence unless terminated pursuant to the terms of our partnership agreement.

Purpose

Under our partnership agreement, the purpose and nature of the business to be conducted by us shall be to engage directly or indirectly in any business activity that is approved by our general partner, in its sole discretion, and that lawfully may be conducted by a limited partnership organized pursuant to the Delaware Act; provided, however, that our general partner shall not cause us to engage, directly or indirectly, in any business activity that our general partner determines would be reasonably likely to cause us to be treated as an association taxable as a corporation or otherwise taxable as an entity for U.S. federal income tax purposes.

Although our general partner has the ability to cause us and our subsidiaries to engage in activities other than those related to the midstream energy business, our general partner currently has no plans to do so 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 our limited partners, other than the implied contractual covenant of good faith and fair dealing. In general, our general partner is authorized to perform all acts it determines to be necessary or appropriate to carry out our purposes and to conduct our business.

Capital Contributions

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

Voting Rights

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

• during the subordination period, the approval of a majority of the outstanding common units, excluding those common units held by our general partner and its affiliates, and a majority of the outstanding subordinated units, voting as separate classes; and

• after the subordination period, the approval of a majority of the outstanding common units.

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Following the completion of this offering, Noble will have the ability to ensure passage of, as well as the ability to ensure the defeat of, any amendment that requires a unit majority by virtue of their ownership of an aggregate common units and             subordinated units, representing an aggregate     % limited partner interest (or             common units and             subordinated units, representing an aggregate     % limited partner interest, if the underwriters exercise in full their option to purchase additional common units).

In voting their common units 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, other than the implied contractual covenant of good faith and fair dealing.

Issuance of additional partnership interests No approval rights.

Amendment of our partnership agreement Certain amendments may be made by the general partner without the approval of the unitholders. Other amendments generally require the approval of a unit majority. Please read “—Amendment of Our Partnership Agreement.”

Merger of our partnership or the sale of all or substantially all of our assets Unit majority. Please read “—Merger, Consolidation, Conversion, Sale or Other Disposition of Assets.”

Dissolution of our partnership Unit majority. Please read “—Termination and Dissolution.”

Continuation of our business upon dissolution Unit majority. Please read “—Termination and Dissolution.”

Withdrawal of the general partner Under most circumstances, the approval of unitholders holding at least a majority of the outstanding common units, excluding common units held by our general partner and its affiliates, is required for the withdrawal of the general partner prior to             , in a manner which would cause a dissolution of our partnership. Please read “—Withdrawal or Removal of Our General Partner.”

Removal of the general partner Not less than 66 ²/₃% of the outstanding units, voting as a single class, including units held by our general partner and its affiliates, for cause. Please read “—Withdrawal or Removal of Our General Partner.”

Transfer of the general partner interest Our general partner may transfer all, but not less than all, of its general partner interest in us without a vote of our unitholders to an affiliate or another person in connection with its merger or consolidation with or into, or sale of all or substantially all of its assets to, such person. The approval of a majority of the outstanding common units, excluding common units held by our general partner and its affiliates, is required in other circumstances for a transfer of the general partner interest to a third party prior to             . Please read “—Transfer of General Partner Interest.”

Transfer of incentive distribution rights Noble may transfer any or all of its incentive distribution rights to an affiliate or another person without a vote of our unitholders. Please read “—Transfer of Incentive Distribution Rights.”

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Reset of incentive distribution levels No approval right.

Transfer of ownership interests in our general partner No approval right. Please read “—Transfer of Ownership Interests in Our General Partner.”

Limited Liability

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

• remove or replace our general partner for cause;

• approve some amendments to our partnership agreement; or

• take other action under our partnership agreement;

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 who reasonably believe that a 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 limited partner 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. Under the Delaware Act, a substituted limited partner of a limited partnership is liable for the obligations of its assignor to make contributions to the partnership, except that such person is not obligated for liabilities unknown to it at the time it became a limited partner and that could not be ascertained from the partnership agreement.

Our operating subsidiaries conduct business in Colorado. We may have subsidiaries that conduct business in other states in the future. Maintenance of our limited liability as a partner or member of our subsidiaries may require compliance with legal requirements in the jurisdictions in which such subsidiaries conduct business, including qualifying such entities 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 interests in our operating subsidiaries or otherwise, it were determined that we were conducting business in any state 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 for cause,

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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.

Issuance of Additional Partnership Interests

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 current or future 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 or to make additional capital contributions to us 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.

Amendment of Our Partnership Agreement

General

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 our limited partners, including any duty to act in the best interests of us or the limited partners, other than the implied contractual covenant of good faith and fair dealing. 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 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.

Prohibited Amendments

No amendment may be made that would, among other actions:

• enlarge the obligations of any limited partner without its consent, unless such is deemed to have occurred as a result of an amendment approved by at least a majority of the type or class of limited partner interests so affected; or

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• enlarge the obligations of, restrict in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable by us to our general partner or any of its affiliates without its consent, which consent may be given or withheld at its option.

The provisions of our partnership agreement preventing the amendments having the effects described in any of the clauses above can be amended upon the approval of the holders of at least 90% of the outstanding units voting together as a single class (including units owned by our general partner and its affiliates). Following the completion of this offering, Noble will own an aggregate of             common units and             subordinated units, representing an aggregate     % limited partner interest (or             common units and             subordinated units, representing an aggregate     % limited partner interest, if the underwriters exercise in full their option to purchase additional common units).

No Unitholder Approval

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

• a change in our name, the location of our principal office, our registered agent or our registered office;

• the admission, substitution, withdrawal or removal of partners in accordance with our partnership agreement;

• a change that our general partner determines to be necessary or appropriate to qualify or continue our qualification as a limited partnership or a partnership in which the limited partners have limited liability under the laws of any state or to ensure that neither we nor any of our subsidiaries will be treated as an association taxable as a corporation or otherwise taxed as an entity for federal income tax purposes;

• an amendment that is necessary, in the opinion of our counsel, to prevent us or our general partner or its directors, officers, agents or trustees, from in any manner, being subjected to the provisions of the Investment Company Act of 1940, the Investment Advisors Act of 1940, or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974, or ERISA, each as amended, whether or not substantially similar to plan asset regulations currently applied or proposed by the U.S. Department of Labor;

• an amendment that (i) sets forth the designations, preferences, rights, powers and duties of any class or series of partnership interests or (ii) our general partner determines to be necessary, appropriate or advisable in connection with the authorization or issuance of additional partnership interests;

• any amendment expressly permitted in our partnership agreement to be made by our general partner acting alone;

• an amendment effected, necessitated or contemplated by a merger agreement or plan of conversion that has been approved under the terms of our partnership agreement;

• any amendment that our general partner determines to be necessary or appropriate to reflect and account for the formation by us of, or our investment in, any corporation, partnership or other entity, in connection with our conduct of activities permitted by our partnership agreement;

• a change in our fiscal year or taxable year and any other changes that our general partner determines to be necessary or appropriate as a result of such change;

• mergers with, conveyances to or conversions into another limited liability entity that is newly formed and has no assets, liabilities or operations at the time of the merger, conveyance or conversion other than those it receives by way of the merger, conveyance or conversion; or

• any other amendments substantially similar to any of the matters described in the clauses above.

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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:

• do not adversely affect in any material respect the limited partners considered as a whole or any particular class of partnership interests as compared to other classes of partnership interests;

• are necessary or appropriate to satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute;

• are necessary or appropriate to facilitate the trading of limited partner interests or to comply with any rule, regulation, guideline or requirement of any securities exchange on which the limited partner interests are or will be listed or admitted to trading;

• are necessary or appropriate for any action taken by our general partner relating to splits or combinations of units under the provisions of our partnership agreement; or

• are required to effect the intent expressed in this prospectus or the intent of the provisions of our partnership agreement or are otherwise contemplated by our partnership agreement.

Opinion of Counsel and Unitholder Approval

For amendments that do not require unitholder approval, our general partner will not be required to obtain an opinion of counsel to the effect that an amendment will not affect the limited liability of any limited partner under Delaware law. 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 such an opinion of counsel.

In addition to the above restrictions, any amendment that would have a material adverse effect on the rights or preferences of any type or class of partnership interests in relation to other classes of partnership interests will require the approval of at least a majority of the type or class of partnership interests so affected. Any amendment that would reduce the percentage of units required to take any action, other than to remove our general partner for cause or call a meeting of unitholders, must be approved by the written consent or the affirmative vote of limited partners whose aggregate outstanding units constitute not less than the percentage sought to be reduced. Any amendment that would increase the percentage of units required to remove our general partner for cause must be approved by the written consent or the affirmative vote of limited partners whose aggregate outstanding units constitute not less than 90% of outstanding units. Any amendment that would increase the percentage of units required to call a meeting of unitholders must be approved by the written consent or the affirmative vote of limited partners whose aggregate outstanding units constitute at least a majority of the outstanding units.

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

A merger, consolidation or conversion of our partnership 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, other than the implied contractual covenant of good faith and fair dealing.

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, among other things, sell, exchange or otherwise dispose of all or substantially all of our assets in a single transaction or a series of related transactions. Our general partner may, however, mortgage, pledge, hypothecate, or grant a security interest in all or substantially all of our assets without that approval. Our general partner may also sell any or all of our assets under a foreclosure or other realization upon those encumbrances without that approval. Finally, our general partner may consummate any merger with another limited liability entity without the prior approval of our unitholders if we are the surviving

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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 an amendment to our partnership agreement requiring unitholder approval, each of our units will be an identical unit of our partnership following the transaction and the partnership interests to be issued by us in such merger do not exceed 20% of our outstanding partnership interests 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 our general partner determines that 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. The 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.

Termination and Dissolution

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

• the withdrawal or removal of our general partner or any other event that results in its ceasing to be our general partner other than by reason of a transfer of its general partner interest in accordance with our partnership agreement or withdrawal or removal followed by approval and admission of a successor;

• the election of our general partner to dissolve us, if approved by the holders of units representing a unit majority;

• the entry of a decree of judicial dissolution of our partnership; or

• there being no limited partners, unless we are continued without dissolution in accordance with the Delaware Act.

Upon a dissolution under the first 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:

• the action would not result in the loss of limited liability of any limited partner; and

• neither our partnership nor any of our subsidiaries would be treated as an association taxable as a corporation or otherwise be taxable as an entity for federal income tax purposes upon the exercise of that right to continue (to the extent not already so treated or taxed).

Liquidation and Distribution of Proceeds

Upon our dissolution, unless we are continued as a new limited partnership, the liquidator authorized to wind up our affairs will, acting with all of the powers of our general partner that are necessary or appropriate to, liquidate our assets and apply the proceeds of the liquidation as described in “Provisions of Our Partnership Agreement Relating to Cash Distributions—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.

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Withdrawal or Removal of Our General Partner

Except as described below, our general partner has agreed not to withdraw voluntarily as our general partner prior to             , without obtaining the approval of the holders of at least a majority of the outstanding common units, excluding common units held by our general partner and its affiliates, and by giving 90 days’ written notice and furnishing an opinion of counsel regarding limited liability and tax matters. On or after             , our general partner may withdraw as general partner without first obtaining approval of any unitholder by giving 90 days’ written notice, and that withdrawal will not constitute a violation of our partnership agreement. Notwithstanding the information above, our general partner may withdraw without unitholder approval upon 90 days’ written notice to the limited partners if at least 50% of the outstanding units are held or controlled by one person and its affiliates other than our general partner and its affiliates. In addition, our partnership agreement permits our general partner in some instances to sell or otherwise transfer all of its general partner interest in us without the approval of the unitholders. Please read “—Transfer of General Partner Interest” and “—Transfer of Incentive Distribution Rights.”

Upon voluntary withdrawal of our general partner by giving notice to the other partners, 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 to continue our business by appointing a successor general partner. Please read “—Termination and Dissolution.”

Our general partner may not be removed unless that removal is both (i) for cause and (ii) approved by the vote of the holders of not less than 66 ²/₃% of our 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 vote of the holders of a majority of the outstanding common units, voting as a separate class, and subordinated units, voting as a separate class. “Cause” is narrowly defined under our partnership agreement to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding the general partner liable to our partnership or any limited partner for actual fraud or willful misconduct in its capacity as our general partner. Cause does not include most cases of charges of poor management of the business. The ownership of more than 33 ¹/₃% of the outstanding units by our general partner and its affiliates would give them the practical ability to prevent our general partner’s removal. Following the completion of this offering, our Noble will own an aggregate of             common units and             subordinated units, representing an aggregate     % limited partner interest (or             common units and             subordinated units, representing an aggregate     % limited partner interest, if the underwriters exercise in full their option to purchase additional common units).

In the event of 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 of the departing general partner 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 of the departing general partner 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 will become a limited partner and its general partner interest will automatically convert into common units pursuant to a valuation of those interests as determined by an investment banking firm or other independent expert selected in the manner described in the preceding paragraph.

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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 for the termination of any employees employed by the departing general partner or its affiliates for our benefit.

Transfer of General Partner Interest

Except for transfer by our general partner of all, but not less than all, of its general partner interest to (1) an affiliate of our general partner (other than an individual), or (2) another entity as part of the merger or consolidation of our general partner with or into such entity or the transfer by our general partner of all or substantially all of its assets to such entity, our general partner may not transfer all or any part of its general partner interest to another person prior to                     , 2025 without the approval of the holders of at least a majority of the outstanding common units, excluding common units held by our general partner and its affiliates. As a condition of this transfer, the transferee must assume, among other things, 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.

Our general partner and its affiliates may at any time transfer units to one or more persons, without unitholder approval, except that they may not transfer subordinated units to us.

Transfer of Ownership Interests in Our General Partner

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

Transfer of Incentive Distribution Rights

At any time, Noble may sell or transfer its incentive distribution rights to an affiliate or third party without the approval of the unitholders.

Change of Management Provisions

Our partnership agreement contains specific provisions that are intended to discourage a person or group from attempting to remove Noble Midstream GP LLC as our general partner or otherwise change our management. 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 and 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 “—Withdrawal or Removal of Our General Partner.”

Limited Call Right

If at any time our general partner and its affiliates 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 such 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’ written notice.

The purchase price in the event of this purchase is the greater of:

• the highest cash price paid by either our general partner or any of its affiliates for any limited partner interests of the class purchased within the 90 days preceding the date on which our general partner first mails notice of its election to purchase those limited partner interests; and

• the current market price calculated in accordance with our partnership agreement as of the date three business days before the date the notice is mailed.

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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 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 limited call right are the same as a sale by that unitholder of his common units in the market. Please read “Material Federal Income Tax Consequences—Disposition of Common Units.”

Possible Redemption of Ineligible Holders

If at any time our general partner determines, with the advice of counsel, that:

(i) the U.S. federal income tax status (or lack of proof of the U.S. federal income tax status) of one or more limited partners or their owners has or is reasonably likely to have 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 the Federal Energy Regulatory Commission or similar regulatory body, or a rate eligibility trigger, or

(ii) we or our subsidiaries are subject to any federal, state or local law or regulation that would create a substantial risk of cancellation or forfeiture of any property in which we have an interest based on the nationality, citizenship or other related status of one or more limited partners or their owners, or a citizenship eligibility trigger,

then our general partner may adopt such amendments to our partnership agreement as it determines to be necessary or appropriate to:

(a) in the case of a rate eligibility trigger, obtain such proof of the U.S. federal income tax status of such limited partners and, to the extent relevant, their owners, as our general partner determines to be necessary or appropriate to reduce the risk of occurrence of a material adverse effect on the rates that can be charged to customers by us or our subsidiaries, or

(b) in the case of a citizenship eligibility trigger, obtain such proof of the nationality, citizenship or other related status of such limited partners and, to the extent relevant, their owners, as our general partner determines to be necessary or appropriate to eliminate or mitigate the risk of cancellation or forfeiture of any properties or interests therein.

Amendments adopted by our general partner may include provisions requiring all limited partners to certify as to their (and their owners’) status as eligible holders upon demand and on a regular basis, as determined by our general partner, and may require transferees of units to so certify prior to being admitted to our partnership as limited partners.

“Eligible holders” are limited partners 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 the Federal Energy Regulatory Commission or similar regulatory body and (ii) nationality, citizenship or other related status does not create and is not reasonably likely to create, as determined by our general partner, a substantial risk of cancellation or forfeiture of any property in which we have an interest.

Amendments adopted by our general partner may provide that (i) any limited partner who fails to furnish, within a reasonable period, requested proof of its (and its owners’) status as an eligible holder or (ii) if upon receipt of such eligibility certificate or other requested information our general partner determines that a limited partner (or its owner) is not an eligible holder, the limited partner interests owned by such limited partner will be subject to redemption. In addition, our general partner will be substituted and treated as the owner of all limited partner interests owned by an ineligible holder.

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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 limited partner interests of the class to be so redeemed multiplied by the number of limited partner interests of each such class included among the redeemable interests. For these purposes, the “current market price” means, as of any date for any class of limited partner interests, the average of the daily closing prices per limited partner interest of such class 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. Any such promissory note will bear interest at the rate of 5% annually and be payable in three equal annual installments of principal and accrued interest, commencing one year after the redemption date. Further, the units will not be entitled to any allocations of income or loss, distributions or voting rights while held by such unitholder.

Meetings; Voting

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 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, if authorized by our general partner, without a meeting if consents in writing describing the action so taken are signed by holders of the number of units that would be necessary to authorize or take that action at a meeting where all limited partners were present and voted. 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 in voting power 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. For all matters presented to the limited partners at a meeting at which a quorum is present for which no minimum or other vote of the limited partners is specifically required pursuant to our partnership agreement, the rules and regulations of any national securities exchange on which the common units are admitted to trading, or applicable law or pursuant to any regulation applicable to us or our partnership interests, a majority of the votes cast by the limited partners holding outstanding units will be deemed to constitute the act of all limited partners (with abstentions and broker non-votes being deemed to not have been cast with respect to such matter). On any matter where a minimum or other vote of limited partners is provided by any provision of our partnership agreement or required by the rules or regulations of any national securities exchange on which the common units are admitted to trading, or applicable law or pursuant to any regulation applicable to us or our partners interests, such minimum or other vote will be the vote of the limited partners required to approve such matter (with the effect of abstentions and broker non-votes to be determined based on the vote of the limited partners required to approve such matter, provided that if the effect of abstentions and broker non-votes is not specified by the applicable rule, regulation or law, and there is no prevailing interpretation of such effect, then abstentions and broker non-votes will be deemed not to have been cast with respect to such matter). The general partner interest does not entitle our general partner to any vote other than its rights as general partner under our partnership agreement, will not be entitled to vote on any action required or permitted to be taken by the unitholders and will not count toward or be considered outstanding when calculating required votes, determining the presence of a quorum, or for similar purposes.

Each record holder of a unit has a vote according to its percentage interest in us, although additional limited partner interests having special voting rights could be issued. Please read “—Issuance of Additional Partnership Interests.” However, if at any time any person or group, other than our general partner and its affiliates, a direct transferee of our general partner and its affiliates or a transferee of such direct transferee, who is notified by our general partner that it will not lose its voting rights, 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

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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 its 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 holders of common units under our partnership agreement will be delivered to the record holder by us or by the transfer agent.

Status as Limited Partner

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 is reflected in our register. Except as described under “—Limited Liability,” the common units will be fully paid, and unitholders will not be required to make additional contributions.

Indemnification

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:

• our general partner;

• any departing general partner;

• any person who is or was an affiliate of our general partner or any departing general partner;

• any person who is or was a director, officer, managing member, manager, general partner, fiduciary or trustee of us or our subsidiaries, an affiliate of us or our subsidiaries or any entity set forth in the preceding three bullet points;

• any person who is or was serving as director, officer, managing member, manager, general partner, fiduciary or trustee of another person owing a fiduciary duty to us or any of our subsidiaries at the request of our general partner or any departing general partner or any of their affiliates, excluding any such person providing, on a fee-for-service basis, trustee, fiduciary of custodial services; and

• any person designated by our general partner because such person’s status, service or relationship expose such person to potential claims or suits relating to our or our subsidiaries’ business and affairs.

Any indemnification under these provisions will only be out of our assets. Unless it otherwise agrees, our general partner 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 will 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 such liabilities under our partnership agreement.

Reimbursement of Expenses

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. 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. The expenses for which we are required to reimburse our general partner are not subject to any caps or other limits. Please read “Certain Relationships and Related Party Transactions—Agreements with our Affiliates in the Connection with the Transactions—Omnibus Agreement.”

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Books and Reports

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

We will mail or make available to record holders of common units, within 90 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 mail or make available summary financial information within 45 days after the close of each quarter (or such shorter period as required by the SEC).

We will furnish each record holder of a unit with information reasonably required for 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 unitholders will depend on the cooperation of unitholders in supplying us with specific information. Every unitholder will receive information to assist such unitholder in determining its federal and state tax liability and filing its federal and state income tax returns, regardless of whether such unitholder supplies us with information.

Right to Inspect Our Books and Records

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

• a current list of the name and last known address of each record holder;

• copies of our partnership agreement and our certificate of limited partnership and all amendments thereto; and

• certain information regarding the status of our business and financial condition.

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 right to information that a limited partner would otherwise have under Delaware law.

Registration Rights

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 partnership interests proposed to be sold by our general partner or any of its affiliates, other than individuals, or their assignees if an exemption from the registration requirements is not otherwise available. We are obligated to pay all expenses incidental to the registration, excluding underwriting discounts and commissions. Please read “Units Eligible for Future Sale.”

Applicable Law; Exclusive Forum

Our partnership agreement is governed by Delaware law.

Our partnership agreement will provide that 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) shall be the exclusive forum for any claims, suits, actions or proceedings (i) arising out of or relating in any way to our partnership agreement (including any claims, suits or actions to interpret, apply or enforce the provisions of our partnership agreement or the duties, obligations or liabilities among our

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partners, or obligations or liabilities of our partners to us, or the rights or powers of, or restrictions on, our partners or us), (ii) brought in a derivative manner on our behalf, (iii) asserting a claim of breach of a duty owed by any of our, or our general partner’s, directors, officers, or other employees, or owed by our general partner, to us or our partners, (iv) asserting a claim against us arising pursuant to any provision of the Delaware Act or (v) asserting a claim against us governed by the internal affairs doctrine. Although we believe this provision benefits us by providing increased consistency in the application of Delaware law in the types of lawsuits to which it applies, the provision may have the effect of discouraging lawsuits against our directors and officers. The enforceability of similar choice of forum provisions in other companies’ certificates of incorporation or similar governing documents have been challenged in legal proceedings, and it is possible that, in connection with any action, a court could find the choice of forum provisions contained in our partnership agreement to be inapplicable or unenforceable in such action.

If any person 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. In addition, our partnership agreement provides that each limited partner irrevocably waives the right to trial by jury in any such claim, suit, action or proceeding.

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, if such court does not have subject matter jurisdiction thereof, any other court located in the State of Delaware with subject matter jurisdiction) in connection with any such claims, suits, actions or proceedings.

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UNITS ELIGIBLE FOR FUTURE SALE

Following the completion of this offering and assuming that the underwriters do not exercise their option to purchase additional common units, our general partner and its affiliates will 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. All of the common units and subordinated units held by our general partner and its affiliates are subject to lock-up restrictions described below. The sale of these units could have an adverse impact on the price of our common units or on any trading market that may develop.

Rule 144

The 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 and directors of our general partner under the 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. Additionally, any common units owned 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 of the Securities Act, or Rule 144, or otherwise. Rule 144 permits securities acquired by an affiliate of the issuer to be sold into the market in an amount that does not exceed, during any three-month period, the greater of:

• 1.0% of the total number of our common units outstanding; or

• the average weekly reported trading volume of our common units for the four weeks prior to the sale.

At the closing of this offering, the following common units will be restricted and may not be resold publicly except in compliance with the registration requirements of the Securities Act, Rule 144 or otherwise.

• common units owned by our general partner and its affiliates; and

• any units acquired by our general partner or any of its affiliates, including the directors and executive officers of our general partner under the directed unit program.

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 three months preceding a sale, and who has beneficially owned his common units for at least six months (provided we are in compliance with the current public information requirement) or one year (regardless of whether we are in compliance with the current public information requirement), would be entitled to sell those common units under Rule 144 without regard to the volume limitations, manner of sale provisions and notice requirements of Rule 144.

Our Partnership Agreement and Registration Rights

Our partnership agreement authorizes us to issue an unlimited number of additional partnership interests and options, rights, warrants and appreciation rights relating to the partnership interests for any partnership purpose at any time and from time to time to such persons for such consideration and on such terms and conditions as our general partner shall determine in its sole discretion, all without the approval of any partners. 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 “Our Partnership Agreement—Issuance of Additional Partnership Interests.”

Under our partnership agreement, our general partner and its affiliates, other than individuals, have the right to cause us to register under the Securities Act and applicable state securities laws the offer and sale of any units

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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 common units or other limited partner interests to require registration of any of these common units or other limited partner interests and to include any of these common units or other limited partner interests in a registration by us of other partnership interests, including common units offered by us or by any unitholder. Our general partner and its affiliates will continue to have these registration rights for two years after Noble Midstream GP LLC ceases to be 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 discounts and commissions. Except as described below, our general partner and its affiliates may sell their common units or other limited partner interests in private transactions at any time, subject to compliance with applicable laws.

Lock-Up Agreements

Our general partner’s executive officers and directors, our general partner and Noble have agreed that for a period of 180 days from the date of this prospectus they will not, without the prior written consent of Barclays Capital Inc. dispose of any common units or any securities convertible into or exchangeable for our common units. Participants in our directed unit program will be subject to similar restrictions. Please read “Underwriting” for a description of these lock-up provisions.

Registration Statement on Form S-8

We intend to file a registration statement on Form S-8 under the Securities Act following this offering to register all common units issued or reserved for issuance under our LTIP. We expect to file this registration statement as soon as practicable. Common units covered by the registration statement on Form S-8 will be eligible for sale in the public market, subject to applicable vesting requirements and the terms of applicable lock-up agreements described above.

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MATERIAL FEDERAL INCOME TAX CONSEQUENCES

This section is a summary of the material U.S. federal income tax consequences that may be relevant to prospective unitholders who are individual citizens or residents of the U.S. and, unless otherwise noted in the following discussion, is the opinion of Andrews Kurth LLP, counsel to our general partner and us, insofar as it relates to legal conclusions with respect to matters of U.S. federal income tax law. This section is based upon current provisions of the Internal Revenue Code of 1986, as amended, or the Internal Revenue Code, existing and proposed Treasury regulations promulgated under the Internal Revenue Code, or the Treasury Regulations, and current administrative rulings and court decisions, all of which are subject to change. Later changes in these authorities may cause the tax consequences to vary substantially from the consequences described below. Unless the context otherwise requires, references in this section to “us” or “we” are references to Noble Midstream Partners LP and our operating subsidiaries.

The following discussion does not comment on all federal income tax matters affecting us or our unitholders and does not describe the application of the alternative minimum tax that may be applicable to certain unitholders. Moreover, the discussion focuses on unitholders who are individual citizens or residents of the U.S. and has only limited application to corporations, estates, entities treated as partnerships for U.S. federal income tax purposes, trusts, nonresident aliens, U.S. expatriates and former citizens or long-term residents of the United States or other unitholders subject to specialized tax treatment, such as banks, insurance companies and other financial institutions, tax-exempt institutions, foreign persons (including, without limitation, controlled foreign corporations, passive foreign investment companies and non-U.S. persons eligible for the benefits of an applicable income tax treaty with the United States), individual retirement accounts (IRAs), real estate investment trusts (REITs) or mutual funds, dealers in securities or currencies, traders in securities, U.S. persons whose “functional currency” is not the U.S. dollar, persons holding their units as part of a “straddle,” “hedge,” “conversion transaction” or other risk reduction transaction, and persons deemed to sell their units under the constructive sale provisions of the Internal Revenue Code. In addition, the discussion only comments to a limited extent on state, local and foreign tax consequences. Accordingly, we encourage each prospective unitholder to consult his own tax advisor in analyzing the state, local and foreign tax consequences particular to him of the ownership or disposition of common units and potential changes in applicable tax laws.

Although we have requested a ruling from the IRS as to whether income derived from our water-related activities constitutes qualifying income, this offering is not contingent upon receipt of a favorable ruling pursuant to that request and no ruling has been requested from the IRS regarding our characterization as a partnership for tax purposes. Instead, we will rely on opinions of Andrews Kurth LLP. Unlike a ruling, an opinion of counsel represents only that counsel’s best legal judgment and does not bind the IRS or the courts. Accordingly, the opinions and statements made herein may not be sustained by a court if contested by the IRS. Any contest of this sort with the IRS may materially and adversely impact the market for the common units and the prices at which common units trade. In addition, the costs of any contest with the IRS, principally legal, accounting and related fees, will result in a reduction in cash available for distribution to our unitholders and our general partner and thus will be borne indirectly by our unitholders and our general partner. Furthermore, the tax treatment of us, or of an investment in us, may be significantly modified by future legislative or administrative changes or court decisions. Any modifications may or may not be retroactively applied.

All statements as to matters of federal income tax law and legal conclusions with respect thereto, but not as to factual matters, contained in this section, unless otherwise noted, are the opinion of Andrews Kurth LLP and are based on the accuracy of the representations made by us.

For the reasons described below, Andrews Kurth LLP has not rendered an opinion with respect to the following specific federal income tax issues: (i) the treatment of a unitholder whose common units are loaned to a short seller to cover a short sale of common units (please read “—Tax Consequences of Unit Ownership—Treatment of Short Sales”); (ii) whether our monthly convention for allocating taxable income and losses is

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permitted by existing Treasury Regulations (please read “—Disposition of Common Units—Allocations Between Transferors and Transferees”) and (iii) whether our method for taking into account Section 743 adjustments is sustainable in certain cases (please read “—Tax Consequences of Unit Ownership—Section 754 Election” and “—Uniformity of Units”).

Partnership Status

A partnership is not a taxable entity and incurs no federal income tax liability. Instead, each partner of a partnership is required to take into account his share of items of income, gain, loss and deduction of the partnership in computing his federal income tax liability, regardless of whether cash distributions are made to him by the partnership. Distributions by a partnership to a partner are generally not taxable to the partnership or the partner unless the amount of cash distributed to him is in excess of the partner’s adjusted basis in his partnership interest. Section 7704 of the Internal Revenue Code provides that publicly-traded partnerships will, as a general rule, be taxed as corporations. However, an exception, referred to as the “Qualifying Income Exception,” exists with respect to publicly-traded partnerships of which 90% or more of the gross income for every taxable year consists of “qualifying income.” Qualifying income includes income and gains derived from the transportation, processing, storage and marketing of crude oil, natural gas and products thereof. Other types of qualifying income include interest (other than from a financial business), dividends, gains from the sale of real property and gains from the sale or other disposition of capital assets 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. Based upon and subject to this estimate, the factual representations made by us and our general partner and a review of the applicable legal authorities, including the Proposed Regulations, Andrews Kurth LLP is of the opinion that at least 90% of our current gross income constitutes qualifying income.

The IRS has made no determination as to our status or the status of our operating subsidiaries for federal income tax purposes or whether our operations generate “qualifying income” under Section 7704 of the Internal Revenue Code. Instead, we will rely on the opinion of Andrews Kurth LLP on such matters. It is the opinion of Andrews Kurth LLP that, based upon the Internal Revenue Code, its regulations, published revenue rulings and court decisions and the representations described below that:

• we will be classified as a partnership for federal income tax purposes; and

• each of our operating subsidiaries will be treated as a partnership or will be disregarded as an entity separate from us for federal income tax purposes.

In rendering its opinion, Andrews Kurth LLP has relied on factual representations made by us and our general partner. The representations made by us and our general partner upon which Andrews Kurth LLP has relied include:

• neither we nor any of the operating subsidiaries has elected or will elect to be treated as a corporation; and

• for each taxable year, more than 90% of our gross income has been and will be income of the type that Andrews Kurth LLP has opined or will opine is “qualifying income” within the meaning of Section 7704(d) of the Internal Revenue Code.

We believe that these representations have been true in the past and expect that these representations will continue to be true in the future.

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

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to make adjustments with respect to our unitholders or pay other amounts), we will be treated as if we had transferred all of our assets, subject to 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 distributed that stock to the unitholders in liquidation of their interests in us. This deemed contribution and liquidation should be tax-free to unitholders and us so long as we, at that time, do not have liabilities in excess of the tax basis of our assets. Thereafter, we would be treated as a corporation for federal income tax purposes.

The present 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 interpretation at any time. For example, from time to time, members of the U.S. Congress and the U.S. President propose and consider substantive changes to the existing federal income tax laws that affect publicly-traded partnerships, including the elimination of partnership tax treatment for publicly-traded partnerships.

On May 5, 2015, the U.S. Treasury Department and the IRS released Proposed Regulations regarding qualifying income under Section 7704(d)(1)(E) of the Code. The U.S. Treasury Department and the IRS have requested comments from industry participants regarding the standards set forth in the Proposed Regulations. The Proposed Regulations provide an exclusive list of industry-specific activities and certain limited support activities that generate qualifying income, including water-related activities when provided for use in drilling and hydraulic fracturing activities.

Although the Proposed Regulations adopt a narrow interpretation of the water-related activities that generate qualifying income, we believe the income that we treat as qualifying satisfies these requirements and, in providing the opinion described above, our counsel will rely on the Proposed Regulations to treat income from certain of our water-related activities as qualifying income and to meet the exception for us to be treated as a partnership for federal income tax purposes.

However, the Proposed Regulations could be changed before they are finalized and could take a position that is contrary to our interpretation. In the event that we do not satisfy the standards set forth in the final regulations for the water-related services or other income that we treat as qualifying, we anticipate being able to continue to treat income from these activities as qualifying income for ten years under special transition rules provided in the Proposed Regulations.

Any modification to the federal income tax laws and interpretations thereof may or may not be retroactively applied and could make it more difficult or impossible to meet the exception for us to be treated as a partnership for federal income tax purposes. Please read “—Partnership Status.” We are unable to predict whether any such changes will ultimately be enacted. However, it is possible that a change in law could affect us, and any such changes could negatively impact the value of an investment in our common units.

If we were treated as an association taxable as a corporation in any taxable year, either as a result of a failure to meet the Qualifying Income Exception or otherwise, our items of income, gain, loss and deduction would be reflected only on our tax return rather than being passed through to our unitholders, and our net income would be taxed to us at corporate rates. In addition, any distribution made to a unitholder would be treated as taxable dividend income, to the extent of our current and accumulated earnings and profits, or, in the absence of earnings and profits, a nontaxable return of capital, to the extent of the unitholder’s tax basis in his common units, or taxable capital gain, after the unitholder’s tax basis in his common units is reduced to zero. Accordingly, taxation as a corporation would result in a material reduction in a unitholder’s cash flow and after-tax return and thus would likely result in a substantial reduction of the value of the units.

The discussion below is based on Andrews Kurth LLP’s opinion that we will be classified as a partnership for federal income tax purposes.

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Limited Partner Status

Unitholders of Noble Midstream Partners LP will be treated as partners of Noble Midstream Partners LP for federal income tax purposes. Also, 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 Noble Midstream Partners LP for federal income tax purposes.

A beneficial owner of common units whose units have been transferred to a short seller to complete a short sale would appear to lose his status as a partner with respect to those units for federal income tax purposes. Please read “—Tax Consequences of Unit Ownership—Treatment of Short Sales.”

Income, gains, losses or deductions 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 income tax purposes would therefore appear to be fully taxable as ordinary income. These holders are urged to consult their tax advisors with respect to the tax consequences to them of holding common units in Noble Midstream Partners LP. The references to “unitholders” in the discussion that follows are to persons who are treated as partners in Noble Midstream Partners LP for federal income tax purposes.

Tax Consequences of Unit Ownership

Flow-Through of Taxable Income

Subject to the discussion below under “—Entity-Level Collections” we will not pay any federal income tax. Instead, each unitholder will be required to report on his income tax return his share of our income, gains, losses and deductions without regard to whether we make cash distributions to him. Consequently, we may allocate income to a unitholder even if he has not received a cash distribution. Each unitholder will be required to include in income his allocable share of our income, gains, losses and deductions for our taxable year ending with or within his taxable year. Our taxable year ends on December 31.

Treatment of Distributions

Distributions by us to a unitholder generally will not be taxable to the unitholder for federal income tax purposes, except to the extent the amount of any such cash distribution exceeds his tax basis in his common units immediately before the distribution. Our cash distributions in excess of a unitholder’s tax basis generally will be considered to be gain from the sale or exchange of the common units, taxable in accordance with the rules described under “—Disposition of Common Units.” Any reduction in a unitholder’s share of our liabilities for which no partner, including the general partner, bears the economic risk of loss, known as “nonrecourse liabilities,” will be treated as a distribution by us of cash to that unitholder. To the extent our distributions cause a unitholder’s “at-risk” amount to be less than zero at the end of any taxable year, he must recapture any losses deducted in previous years. Please read “—Limitations on Deductibility of Losses.”

A decrease in a unitholder’s percentage interest in us because of our issuance of additional common units will decrease his share of our nonrecourse liabilities, and thus will result in a corresponding deemed distribution of cash. This deemed distribution may constitute a non-pro rata distribution. A non-pro rata distribution of money or property may result in ordinary income to a unitholder, regardless of his tax basis in his common units, if the distribution reduces the unitholder’s share of our “unrealized receivables,” including depreciation recapture or substantially appreciated “inventory items,” each as defined in the Internal Revenue Code, and collectively, “Section 751 Assets.” To that extent, the unitholder will be treated as having been distributed his proportionate share of the Section 751 Assets and then having exchanged those assets with us in return for the non-pro rata portion of the actual distribution made to him. This latter deemed exchange will generally result in the unitholder’s realization of ordinary income, which will equal the excess of (1) the non-pro rata portion of that distribution over (2) the unitholder’s tax basis (often zero) for the share of Section 751 Assets deemed relinquished in the exchange.

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Ratio of Taxable Income to Distributions

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 December 31, 2018, 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 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.

The actual percentage of distributions that will constitute taxable income could be higher or lower than expected, and any differences could be material and could materially affect the value of the common units. For example, the ratio of allocable taxable income to cash distributions to a purchaser of common units in this offering will be greater, and perhaps substantially greater, than our estimate with respect to the period described above if:

• gross income from operations exceeds the amount required to make minimum quarterly distributions on all units, yet we only distribute the minimum quarterly distributions on all units; or

• we make a future offering of common units and use the proceeds of the offering in a manner that does not produce substantial additional deductions during the period described above, such as to repay indebtedness outstanding at the time of this offering or to acquire property that is not eligible for depreciation or amortization for federal income tax purposes or that is depreciable or amortizable at a rate significantly slower than the rate applicable to our assets at the time of this offering.

Basis of Common Units

A unitholder’s initial tax basis for his common units will be the amount he paid for the common units plus his share of our nonrecourse liabilities. That basis will be increased by his share of our income and by any increases in his share of our nonrecourse liabilities. That basis will be decreased, but not below zero, by distributions from us, by the unitholder’s share of our losses, by any decreases in his share of our nonrecourse liabilities and by his share of our expenditures that are not deductible in computing taxable income and are not required to be capitalized. A unitholder will have no share of our debt that is recourse to our general partner to the extent of the general partner’s “net value” as defined in Treasury Regulations under Section 752 of the Internal Revenue Code, but will have a share, generally based on his share of profits, of our nonrecourse liabilities. Please read “—Disposition of Common Units—Recognition of Gain or Loss.”

Limitations on Deductibility of Losses

The deduction by a unitholder of his share of our losses will be limited to the tax basis in his units and, in the case of an individual unitholder, estate, trust, or corporate unitholder (if more than 50% of the value of the corporate unitholder’s stock is owned directly or indirectly by or for five or fewer individuals or some tax-exempt organizations) to the amount for which the unitholder is considered to be “at risk” with respect to our activities, if that is less than his tax basis. A common unitholder subject to these limitations must recapture losses deducted in previous years to the extent that distributions cause his 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 these limitations will carry forward and will be allowable as a deduction to the extent that his at-risk amount is subsequently increased, provided such losses do not exceed such common unitholder’s tax basis in his common units. Upon the taxable disposition of a unit, any gain recognized by a unitholder can be offset by losses that were previously suspended by the at-risk limitation but may not be offset by losses suspended by the basis limitation. Any loss previously suspended by the at-risk limitation in excess of that gain would no longer be utilizable.

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In general, a unitholder will be at risk to the extent of the tax basis of his units, excluding any portion of that basis attributable to his share of our nonrecourse liabilities, reduced by (i) any portion of that basis representing amounts otherwise protected against loss because of a guarantee, stop loss agreement or other similar arrangement and (ii) any amount of money he borrows to acquire or hold his units, if the lender of those borrowed funds owns an interest in us, is related to the unitholder or can look only to the units for repayment. A unitholder’s at-risk amount will increase or decrease as the tax basis of the unitholder’s units increases or decreases, other than tax basis increases or decreases attributable to increases or decreases in his share of our nonrecourse liabilities.

In addition to the basis and at-risk limitations on the deductibility of losses, the passive loss limitations generally provide that individuals, estates, trusts and some closely held C corporations and personal service corporations can deduct losses from passive activities, which are generally trade or business activities in which the taxpayer does not materially participate, only to the extent of the taxpayer’s income from those passive activities. The passive loss limitations are applied separately with respect to each publicly-traded partnership. Consequently, any passive losses we generate will only be available to offset our passive income generated in the future and will not be available to offset income from other passive activities or investments, including our investments or a unitholder’s investments in other publicly-traded partnerships, or the unitholder’s salary, active business or other income. Passive losses that are not deductible because they exceed a unitholder’s share of income we generate may be deducted in full when he disposes of his entire investment in us in a fully taxable transaction with an unrelated party. The passive loss limitations are applied after other applicable limitations on deductions, including the at-risk rules and the basis limitation.

A unitholder’s share of our net income may be offset by any of our suspended passive losses, but it may not be offset by any other current or carryover losses from other passive activities, including those attributable to other publicly-traded partnerships.

Limitations on Interest Deductions

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:

• interest on indebtedness properly allocable to property held for investment;

• our interest expense attributed to portfolio income; and

• the portion of interest expense incurred to purchase or carry an interest in a passive activity to the extent attributable to portfolio income.

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 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, but generally does not include gains attributable to the disposition of property held for investment or (if applicable) qualified dividend income. The IRS has indicated that the net passive income earned by a publicly-traded partnership will be treated as investment income to its unitholders. In addition, the unitholder’s share of our portfolio income will be treated as investment income.

Entity-Level Collections

If we are required or elect under applicable law to pay any federal, state, local or foreign income tax on behalf of any unitholder or our general partner or any former unitholder, we are authorized to pay those taxes from our funds. That payment, if made, will be treated as a distribution of cash to the unitholder on whose behalf

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the payment was made. If the payment is made on behalf of a person whose identity cannot be determined, we are authorized to treat the payment as a distribution to all current unitholders. We are authorized to amend our partnership agreement in the manner necessary to maintain uniformity of the intrinsic tax characteristics of units and to adjust later distributions, so that after giving effect to these distributions, the priority and characterization of distributions otherwise applicable under our partnership agreement is maintained as nearly as is practicable. Payments by us as described above could give rise to an overpayment of tax on behalf of an individual unitholder in which event the unitholder would be required to file a claim in order to obtain a credit or refund.

Allocation of Income, Gain, Loss and Deduction

In general, 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 to the common units in excess of distributions to the 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 to account for (i) any difference between the tax basis and fair market value of our assets at the time of this offering and (ii) any difference between the tax basis and fair market value of any property contributed to us that exists at the time of such contribution, together referred to in this discussion as the “Contributed Property.” The effect of these allocations, referred to as “Section 704(c) Allocations,” to a unitholder purchasing common units from us in this offering will be essentially the same as if the tax bases of our assets were equal to their fair market values at the time of this offering. In the event we issue additional common units or engage in certain other transactions in the future, “reverse Section 704(c) Allocations,” similar to the Section 704(c) Allocations described above, will be made to all of our unitholders immediately prior to such issuance or other transactions to account for the difference between the “book” basis for purposes of maintaining capital accounts and the fair market value of all property held by us at the time of such issuance or future transaction. In addition, items of recapture income will be allocated to the extent possible to the unitholder who was allocated the deduction giving rise to the treatment of that gain as recapture income in order to minimize the recognition of ordinary income by some unitholders. Finally, although we do not expect that our operations will result in the creation of negative capital accounts, if negative capital accounts nevertheless result, items of our income and gain will be allocated in an amount and manner sufficient to eliminate the negative balance as quickly as possible.

An allocation of items of our income, gain, loss or deduction, other than an allocation required by the Internal Revenue Code to eliminate the difference between a partner’s “book” capital account, credited with the fair market value of Contributed Property, and “tax” capital account, credited with the tax basis of Contributed Property, referred to in this discussion as the “Book-Tax Disparity,” will generally be given effect for federal income tax purposes in determining a partner’s share of an item of income, gain, loss or deduction only if the allocation has “substantial economic effect.” In any other case, a partner’s share of an item will be determined on the basis of his interest in us, which will be determined by taking into account all the facts and circumstances, including:

• his relative contributions to us;

• the interests of all the partners in profits and losses;

• the interest of all the partners in cash flow; and

• the rights of all the partners to distributions of capital upon liquidation.

Andrews Kurth LLP 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 under our partnership agreement will be given effect for federal income tax purposes in determining a partner’s share of an item of income, gain, loss or deduction.

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Treatment of Short Sales

A unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of those units. If so, he would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition. As a result, during this period:

• any of our income, gain, loss or deduction with respect to those units would not be reportable by the unitholder;

• any cash distributions received by the unitholder as to those units would be fully taxable; and

• while not entirely free from doubt, all of these distributions would appear to be ordinary income.

Because there is no direct or indirect controlling authority on the issue relating to partnership interests, Andrews Kurth LLP has not rendered an opinion regarding the tax treatment of a unitholder whose common units are loaned to a short seller to cover a short sale of common units; therefore, unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to consult a tax advisor to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from borrowing and loaning their units. The IRS has previously 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.”

Tax Rates

Under current law, the highest marginal U.S. federal income tax rate applicable to ordinary income of individuals is 39.6% and the highest marginal U.S. federal income tax rate applicable to long-term capital gains (generally, capital gains on certain assets held for more than twelve months) of individuals is 20%. Such rates are subject to change by new legislation at any time.

In addition, a 3.8% Medicare tax is imposed on 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 units. In the case of an individual, the tax will be imposed on the lesser of (i) the unitholder’s net investment income and (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 the unitholder is married and filing separately) or $200,000 (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 and (ii) the excess adjusted gross income over the dollar amount at which the highest income tax bracket applicable to an estate or trust begins.

Section 754 Election

We will make the election permitted by Section 754 of the Internal Revenue Code. That election is irrevocable without the consent of the IRS unless there is a constructive termination of the partnership. Please read “—Disposition of Common Units—Constructive Termination.” The election will generally permit us to adjust a common unit purchaser’s tax basis in our assets (“inside basis”) under Section 743(b) of the Internal Revenue Code to reflect his purchase price. This election does not apply with respect to a person who purchases common units directly from us. The Section 743(b) adjustment belongs to the purchaser and not to other unitholders. For purposes of this discussion, the inside basis in our assets with respect to a unitholder will be considered to have two components: (1) his share of our tax basis in our assets (“common basis”) and (2) his Section 743(b) adjustment to that basis.

We will adopt the remedial allocation method as to all our properties. Where the remedial allocation method is adopted, the Treasury Regulations under Section 743 of the Internal Revenue Code require a portion of the

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Section 743(b) adjustment that is attributable to recovery property that is subject to depreciation under Section 168 of the Internal Revenue Code and whose book basis is in excess of its tax basis to be depreciated over the remaining cost recovery period for the property’s unamortized Book-Tax Disparity. Under Treasury Regulation Section 1.167(c)-1(a)(6), a Section 743(b) adjustment attributable to property subject to depreciation under Section 167 of the Internal Revenue Code, rather than cost recovery deductions under Section 168, is generally required to be depreciated using either the straight-line method or the 150% declining balance method. Under our partnership agreement, our general partner is authorized to take a position to preserve the uniformity of units even if that position is not consistent with these and any other Treasury Regulations. Please read “—Uniformity of Units.”

We intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized Book-Tax Disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the property’s unamortized Book-Tax Disparity, or treat that portion as non-amortizable to the extent attributable to property which is not amortizable. This method is consistent with the methods employed by other publicly-traded partnerships but is arguably inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets. To the extent this Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized Book-Tax Disparity, we will apply the rules described in the Treasury Regulations and legislative history. If we determine that this position cannot reasonably be taken, we may take a depreciation or amortization position under which all purchasers acquiring units in the same month would receive depreciation or amortization, whether attributable to common basis or a Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our assets. This kind of aggregate approach may result in lower annual depreciation or amortization deductions than would otherwise be allowable to some unitholders. Please read “—Uniformity of Units.” A unitholder’s tax basis for his common units is reduced by his share of our deductions (whether or not such deductions were claimed on an individual’s income tax return) so that any position we take that understates deductions will overstate the common unitholder’s basis in his common units, which may cause the unitholder to understate gain or overstate loss on any sale of such units. Please read “—Disposition of Common Units—Recognition of Gain or Loss.” Andrews Kurth LLP is unable to opine as to whether our method for taking into account Section 743 adjustments is sustainable for property subject to depreciation under Section 167 of the Internal Revenue Code or if we use an aggregate approach as described above, as there is no direct or indirect controlling authority addressing the validity of these positions. Moreover, the IRS may challenge our position with respect to depreciating or amortizing the Section 743(b) adjustment we take to preserve the uniformity of the units. If such a challenge were sustained, the gain from the sale of units might be increased without the benefit of additional deductions.

A Section 754 election is advantageous if the transferee’s tax basis in his units is higher than the units’ share of the aggregate tax basis of our assets immediately prior to the transfer. In that case, as a result of the election, the transferee would have, among other items, a greater amount of depreciation deductions and his share of any gain or loss on a sale of our assets would be less. Conversely, a Section 754 election is disadvantageous if the transferee’s tax basis in his units is lower than those units’ share of the aggregate tax basis of our assets immediately prior to the transfer. Thus, the fair market value of the units may be affected either favorably or unfavorably by the election. A basis adjustment is required regardless of whether a Section 754 election is made in the case of a transfer of an interest in us if we have a substantial built-in loss immediately after the transfer, or if we distribute property and have a substantial basis reduction. Generally, a built-in loss or a basis reduction is substantial if it exceeds $250,000.

The calculations involved in the Section 754 election are complex and will be made on the basis of assumptions as to the value of our assets and other matters. For example, the allocation of the Section 743(b) adjustment among our assets must be made in accordance with the Internal Revenue Code. The IRS could seek to reallocate some or all of any Section 743(b) adjustment allocated by us to our tangible assets to goodwill instead. Goodwill, as an intangible asset, is generally nonamortizable or amortizable over a longer period of time or under

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a less accelerated method than our tangible assets. We cannot assure you that the determinations we make will not be successfully challenged by the IRS and that the deductions resulting from them will not be reduced or disallowed altogether. Should the IRS require a different 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 units may be allocated more income than he would have been allocated had the election not been revoked.

Tax Treatment of Operations

Accounting Method and Taxable Year

We 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 income his share of our income, gain, loss and deduction for our taxable year ending within or with his 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 his units following the close of our taxable year but before the close of his taxable year must include his share of our income, gain, loss and deduction in income for his taxable year, with the result that he will be required to include in income for his taxable year his share of more than twelve months of our income, gain, loss and deduction. Please read “—Disposition of Common Units—Allocations Between Transferors and Transferees.”

Tax Basis, Depreciation and Amortization

The tax basis of our assets will be used for purposes of computing depreciation and cost recovery deductions and, ultimately, gain or loss on the disposition of those 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 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 Unit Ownership—Allocation of Income, Gain, Loss and Deduction.”

The costs we incur in selling our units (called “syndication expenses”) must be capitalized and cannot be deducted currently, ratably or upon our termination. There are uncertainties regarding the classification of 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.

Valuation and Tax Basis of Our Properties

The federal income tax consequences of the ownership and disposition of units will depend in part on our estimates of the relative fair market values, and the tax bases, 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 basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or basis are later found to be incorrect, the character and amount of items of income, gain, loss or deductions previously reported by unitholders might change, and unitholders might be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.

Disposition of Common Units

Recognition of Gain or Loss

Gain or loss will be recognized on a sale of units equal to the difference between the amount realized and the unitholder’s tax basis for the units sold. A unitholder’s amount realized will be measured by the sum of the

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cash or the fair market value of other property received by him plus his share of our nonrecourse liabilities. Because the amount realized includes a unitholder’s share of our nonrecourse liabilities, the gain recognized on the sale of units could result in a tax liability in excess of any cash received from the sale.

Prior distributions from us that in the aggregate were in excess of cumulative net taxable income for a common unit and, therefore, decreased a unitholder’s tax basis in that common unit will, in effect, become taxable income if the common unit is sold at a price greater than the unitholder’s tax basis in that common unit, even if the price received is less than his original cost.

Except as noted below, gain or loss recognized by a unitholder, other than a “dealer” in units, on the sale or exchange of a unit will generally be taxable as capital gain or loss. Capital gain recognized by an individual on the sale of units held for more than twelve months will generally be taxed at the U.S. federal income tax rate applicable to long-term capital gains. However, a portion of this gain or loss, which will likely be substantial, will be separately computed and taxed as ordinary income or loss under Section 751 of the Internal Revenue Code to the extent attributable to assets giving rise to depreciation recapture or other “unrealized receivables” or to “inventory items” we own. The term “unrealized receivables” includes potential recapture items, including depreciation recapture. Ordinary income attributable to unrealized receivables, inventory items and depreciation recapture may exceed net taxable gain realized upon the sale of a unit and may be recognized even if there is a net taxable loss realized on the sale of a unit. Thus, a unitholder may recognize both ordinary income and a capital loss upon a sale of units. Capital losses may offset capital gains and no more than $3,000 of ordinary income, in the case of individuals, and may only be used to offset capital gains in the case of corporations. Both ordinary income and capital gain recognized on a sale of units may be subject to the NIIT in certain circumstances. Please read “—Tax Consequences of Unit Ownership—Tax Rates.”

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

Specific provisions of the Internal Revenue Code affect the taxation of some financial products and securities, including partnership interests, by treating a taxpayer as having sold an “appreciated” partnership interest, one in which gain would be recognized if it were sold, assigned or terminated at its fair market value, if the taxpayer or related persons enter(s) into:

• a short sale;

• an offsetting notional principal contract; or

• a futures or forward contract;

in each case, with respect to the partnership interest or substantially identical property.

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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 also authorized to issue 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.

Allocations Between Transferors and Transferees

In general, our taxable income and losses 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 units owned by each of them as of the opening of the applicable exchange on the first business day of the month, which we refer to in this prospectus as the “Allocation Date.” However, gain or loss realized on a sale or other disposition of our assets other than in the ordinary course of business will be allocated among the unitholders on the Allocation Date in the month in which that gain or loss is recognized. As a result, a unitholder transferring units may be allocated income, gain, loss and deduction realized after the date of transfer.

Although simplifying conventions are contemplated by the Internal Revenue Code and most publicly-traded partnerships use similar simplifying conventions, the use of this method may not be permitted under existing Treasury Regulations as there is no direct or indirect controlling authority on this issue. The U.S. Department of the Treasury and the IRS have issued proposed Treasury Regulations that provide a safe harbor pursuant to which a publicly-traded partnership may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders, although such tax items must be prorated on a daily basis. Existing publicly-traded partnerships are entitled to rely on these proposed Treasury Regulations; however, they are not binding on the IRS and are subject to change until final Treasury Regulations are issued. Accordingly, Andrews Kurth LLP is unable to opine on the validity of this method of allocating income and deductions between transferor and transferee unitholders because the issue has not been finally resolved by the IRS or the courts. If this method is not allowed under the Treasury Regulations, or only applies to transfers of less than all of the unitholder’s interest, our taxable income or losses might be reallocated among the unitholders. We are authorized to revise our method of allocation between transferor and transferee unitholders, as well as unitholders whose interests vary during a taxable year, to conform to a method permitted under future Treasury Regulations. A unitholder who owns units at any time during a quarter and who disposes of them prior to the record date set for a cash distribution for that quarter will be allocated items of our income, gain, loss and deductions attributable to that quarter through the month of disposition but will not be entitled to receive that cash distribution.

Notification Requirements

A unitholder who sells any of his units is generally required to notify us in writing of that sale within 30 days after the sale (or, if earlier, January 15 of the year following the sale). A purchaser of units who purchases units from another unitholder is also generally required to notify us in writing of that purchase within 30 days after the purchase. Upon receiving such notifications, we are required to notify the IRS of that transaction and to furnish specified information to the transferor and transferee. Failure to notify us of a purchase 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 U.S. and who effects the sale or exchange through a broker who will satisfy such requirements.

Constructive Termination

We will be considered to have technically 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. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest

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will be counted only once. Our technical 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 (and our unitholders could receive two schedules K-1 if relief was not available, as described below) for one fiscal year and could result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead we would be treated as a new partnership for federal income tax purposes. If treated as a new partnership, we must make new tax elections, including a new election under Section 754 of the Internal Revenue Code, and could be subject to penalties if we are unable to determine that a termination occurred. The IRS has announced a publicly-traded partnership technical termination relief program whereby, if a publicly-traded partnership that technically terminated requests publicly-traded partnership technical termination relief and such relief is granted by the IRS, among other things, the partnership will only have to provide one Schedule K-1 to unitholders for the year notwithstanding two partnership tax years.

Uniformity of Units

Because we cannot match transferors and transferees of units, we must maintain uniformity of the economic and tax characteristics of the units to a purchaser of these units. In the absence of uniformity, we may be unable to completely comply with a number of federal income tax requirements, both statutory and regulatory. A lack of uniformity can result from a literal application of Treasury Regulation Section 1.167(c)-1(a)(6). Any non-uniformity could have a negative impact on the value of the units. Please read “—Tax Consequences of Unit Ownership—Section 754 Election.” We intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized Book-Tax Disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the property’s unamortized Book-Tax Disparity, or treat that portion as nonamortizable, to the extent attributable to property the common basis of which is not amortizable, consistent with the regulations under Section 743 of the Internal Revenue Code, even though that position may be inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets.

Please read “—Tax Consequences of Unit Ownership—Section 754 Election.” To the extent that the Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized Book-Tax Disparity, we will apply the rules described in the Treasury Regulations and legislative history. If we determine that this position cannot reasonably be taken, we may adopt a depreciation and amortization position under which all purchasers acquiring units in the same month would receive depreciation and amortization deductions, whether attributable to common basis or a Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our assets. If this position is adopted, it may result in lower annual depreciation and amortization deductions than would otherwise be allowable to some unitholders and risk the loss of depreciation and amortization deductions not taken in the year that these deductions are otherwise allowable. This position will not be adopted if we determine that the loss of depreciation and amortization deductions will have a material adverse effect on the unitholders. If we choose not to utilize this aggregate method, we may use any other reasonable depreciation and amortization method to preserve the uniformity of the intrinsic tax characteristics of any units that would not have a material adverse effect on the unitholders. In either case, and as stated above under “—Tax Consequences of Unit Ownership—Section 754 Election,” Andrews Kurth LLP has not rendered an opinion with respect to these methods. Moreover, the IRS may challenge any method of depreciating the Section 743(b) adjustment described in this paragraph. If this challenge were sustained, the uniformity of units might be affected, and the gain from the sale of units might be increased without the benefit of additional deductions. Please read “—Disposition of Common Units—Recognition of Gain or Loss.”

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Tax-Exempt Organizations and Other Investors

Ownership of units by employee benefit plans, other tax-exempt organizations, non-resident aliens, foreign corporations and other foreign persons raises issues unique to those investors and, as described below to a limited extent, may have substantially adverse tax consequences to them. If you are a tax-exempt entity or a non-U.S. person, you should consult your tax advisor before investing in our common units. Employee benefit plans and most other organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, are subject to federal income tax on unrelated business taxable income. Virtually all of our income allocated to a unitholder that is a tax-exempt organization will be unrelated business taxable income and will be taxable to it.

Non-resident aliens and foreign corporations, trusts or estates that own units will be considered to be engaged in business in the U.S. because of the ownership of units. As a consequence, they will be required to file federal tax returns to report their share of our income, gain, loss or deduction and pay federal income tax at regular rates on their share of our net income or gain. Moreover, under rules applicable to publicly-traded partnerships, our quarterly distribution to foreign unitholders will be subject to withholding at the highest applicable effective tax rate. Each foreign unitholder must obtain a taxpayer identification number from the IRS and submit that number to our transfer agent on a Form W-8BEN, W-8BEN-E or applicable substitute form in order to obtain credit for these withholding taxes. A change in applicable law may require us to change these procedures.

In addition, because a foreign corporation that owns units will be treated as engaged in a U.S. trade or business, that corporation may be subject to the U.S. branch profits tax at a rate of 30%, in addition to regular federal income tax, on its share of our earnings and profits, as adjusted for changes in the foreign corporation’s “U.S. net equity,” that is effectively connected with the conduct of a U.S. trade or business. That tax may be reduced or eliminated by an income tax treaty between the U.S. 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 Internal Revenue Code.

A foreign 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 unit to the extent the gain is effectively connected with a U.S. trade or business of the foreign unitholder. Under a ruling published by the IRS, interpreting the scope of “effectively connected income,” a foreign unitholder would be considered to be engaged in a trade or business in the U.S. by virtue of the U.S. activities of the partnership, and part or all of that unitholder’s gain would be effectively connected with that unitholder’s indirect U.S. trade or business. Moreover, under the Foreign Investment in Real Property Tax Act, a foreign unitholder generally will be subject to U.S. federal income tax upon the sale or disposition of a common unit if (i) he owned (directly or constructively applying certain attribution rules) more than 5% of our common units at any time during the five-year period ending on the date of such disposition and (ii) 50% or more of the fair market value of all of our assets consisted of U.S. real property interests at any time during the shorter of the period during which such unitholder held the common units or the five-year period ending on the date of disposition. More than 50% of our assets may consist of U.S. real property interests. Therefore, foreign unitholders may be subject to federal income tax on gain from the sale or disposition of their units.

Administrative Matters

Information Returns and Audit Procedures

We intend to furnish to each unitholder, within 90 days after the close of each calendar year, specific tax information, including a Schedule K-1, which describes his 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

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unitholder’s share of income, gain, loss and deduction. We cannot assure you that those positions will yield a result that conforms to the requirements of the Internal Revenue Code, Treasury Regulations or administrative interpretations of the IRS. Neither we nor Andrews Kurth LLP can assure prospective unitholders that the IRS will not successfully contend in court that those positions are impermissible. Any challenge by the IRS could negatively affect the value of the units.

The IRS may audit our federal income tax information returns. Adjustments resulting from an IRS audit may require each unitholder to adjust a prior year’s tax liability, and possibly may result in an audit of his return. Any audit of a unitholder’s return could result in adjustments not related to our returns as well as those related to our returns.

Partnerships generally are treated as separate entities for purposes of federal 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 with the partners. The Internal Revenue Code requires that one partner be designated as the “Tax Matters Partner” for these purposes. Our partnership agreement names our general partner as our Tax Matters Partner.

The Tax Matters Partner will make some elections on our behalf and on behalf of unitholders. In addition, the Tax Matters Partner can extend the statute of limitations for assessment of tax deficiencies against unitholders for items in our 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 will go forward, and each unitholder with an interest in the outcome may participate.

A unitholder must file a statement with the IRS identifying the treatment of any item on his 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.

Nominee Reporting

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

• the name, address and taxpayer identification number of the beneficial owner and the nominee;

• whether the beneficial owner is:

• a person that is not a U.S. person;

• a foreign government, an international organization or any wholly-owned agency or instrumentality of either of the foregoing; or

• a tax-exempt entity;

• the amount and description of units held, acquired or transferred for the beneficial owner; and

• specific information including the dates of acquisitions and transfers, means of acquisitions and transfers, and acquisition cost for purchases, as well as the amount of net proceeds from dispositions.

Brokers and financial institutions are required to furnish additional information, including whether they are U.S. persons and specific information on units they acquire, hold or transfer for their own account. A penalty of $100 per failure, up to a maximum of $1,500,000 per calendar year, is imposed by the Internal Revenue Code for failure to report that information to us. The nominee is required to supply the beneficial owner of the units with the information furnished to us.

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Accuracy-Related Penalties

An additional tax equal to 20% of the amount of any portion 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, is imposed by the Internal Revenue Code. No penalty will be imposed, however, for any portion of an underpayment if it is shown that there was a reasonable cause for that portion and that the taxpayer acted in good faith regarding that portion.

For individuals, a substantial understatement of income tax in any taxable year exists if the amount of the understatement exceeds the greater of 10% of the tax required to be shown on the return for the taxable year or $5,000 ($10,000 for most corporations). The amount of any understatement subject to penalty generally is reduced if any portion is attributable to a position adopted on the return:

• for which there is, or was, “substantial authority”; or

• as to which there is a reasonable basis and the pertinent facts of that position are disclosed on the return.

If any item of income, gain, loss or deduction included in the distributive shares of unitholders might result in that kind of an “understatement” of income for which no “substantial authority” exists, we must disclose the pertinent facts on our return. In addition, we will make a reasonable effort to furnish sufficient information for unitholders to make adequate disclosure on their returns and to take other actions as may be appropriate to permit unitholders to avoid liability for this penalty. More stringent rules apply to “tax shelters,” which we do not believe includes us, or any of our investments, plans or arrangements.

A substantial valuation misstatement exists if (a) the value of any property, or the adjusted basis of any property, claimed on a tax return is 150% or more of the amount determined to be the correct amount of the valuation or adjusted basis, (b) the price for any property or services (or for the use of property) claimed on any such return with respect to any transaction between persons described in Internal Revenue Code Section 482 is 200% or more (or 50% or less) of the amount determined under Section 482 to be the correct amount of such price, or (c) the net Internal Revenue Code Section 482 transfer price adjustment for the taxable year exceeds the lesser of $5 million or 10% of the taxpayer’s gross receipts. No penalty is imposed unless the portion of the underpayment attributable to a substantial valuation misstatement exceeds $5,000 ($10,000 for most corporations). If the valuation claimed on a return is 200% or more than the correct valuation or certain other thresholds are met, the penalty imposed increases to 40%. We do not anticipate making any valuation misstatements.

In addition, the 20% accuracy-related penalty also applies to any portion of an underpayment of tax that is attributable to transactions lacking economic substance. To the extent that such transactions are not disclosed, the penalty imposed is increased to 40%. Additionally, there is no reasonable cause defense to the imposition of this penalty to such transactions.

Reportable Transactions

If we were to engage in a “reportable transaction,” we (and possibly you and others) would be required to make a detailed disclosure of the transaction to the IRS. A transaction may be a reportable transaction based upon any of several factors, including the fact that it is a type of tax avoidance transaction publicly identified by the IRS as a “listed transaction” or that it produces certain kinds of losses for partnerships, individuals, S corporations, and trusts in excess of $2 million in any single year, or $4 million in any combination of six successive tax years. Our participation in a reportable transaction could increase the likelihood that our federal income tax information return (and possibly your tax return) would be audited by the IRS. Please read “—Information Returns and Audit Procedures.”

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Moreover, if we were to participate in a reportable transaction with a significant purpose to avoid or evade tax, or in any listed transaction, you may be subject to the following additional consequences:

• accuracy-related penalties with a broader scope, significantly narrower exceptions, and potentially greater amounts than described above at “—Accuracy-Related Penalties”;

• for those persons otherwise entitled to deduct interest on federal tax deficiencies, nondeductibility of interest on any resulting tax liability; and

• in the case of a listed transaction, an extended statute of limitations.

We do not expect to engage in any “reportable transactions.”

State, Local, Foreign and Other Tax Considerations

In addition to federal income taxes, unitholders may be subject to other taxes, including state, local and foreign 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 currently own property or do business in a substantial number of states, virtually all of which impose a personal income tax and many impose an income tax on corporations and other entities. We may also own property or do business in other states in the future. Although an analysis of those various taxes is not presented here, each prospective unitholder should consider their potential impact on his investment in us.

Although you may not be required to file a return and pay taxes in some jurisdictions because your income from that jurisdiction falls below the filing and payment requirement, you will be required to file income tax returns and to pay income taxes in many of the jurisdictions in which we do business or own property and may be subject to penalties for failure to comply with those requirements. 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. Amounts withheld will be treated as if distributed to unitholders for purposes of determining the amounts distributed by us. Please read “—Tax Consequences of Unit Ownership—Entity-Level Collections.”

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 urge each prospective unitholder to consult, and depend on, 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 foreign, as well as U.S. federal tax returns, that may be required of it. Andrews Kurth LLP has not rendered an opinion on the state, local, alternative minimum tax or non-U.S. tax consequences of an investment in us.

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INVESTMENT IN NOBLE MIDSTREAM PARTNERS LP BY EMPLOYEE BENEFIT PLANS

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 Internal Revenue Code and may be subject to provisions under certain other laws or regulations that are similar to ERISA or the Internal Revenue Code, or Similar Laws. For these purposes the term “employee benefit plan” includes, but is not limited to, qualified pension, profit-sharing and stock bonus plans, certain Keogh plans, certain simplified employee pension plans, IRAs and tax deferred annuities established or maintained by an employer or employee organization, and entities whose underlying assets are considered to include “plan assets” of any such plan, account or arrangement, each, a Plan. This summary is based on the provisions of ERISA and the Internal Revenue Code, and the related regulations and administrative and judicial interpretations, as of the date hereof. This summary does not purport to be complete, and no assurance can be given that future legislation, court decisions or administrative regulations, rulings or pronouncements will not significantly modify the requirements summarized herein. Any such changes may be retroactive and thereby apply to transactions entered into before the date of their enactment or release.

General Fiduciary Matters

ERISA and the Internal Revenue Code impose certain duties on persons who are fiduciaries of an a Plan that is subject to Title I of ERISA or Section 4975 of the Internal Revenue Code, or an ERISA Plan, and prohibit certain transactions involving the assets of an ERISA Plan and its fiduciaries or other interested parties. Under ERISA and the Internal Revenue Code, any person who exercises any discretionary authority or control over the administration of an ERISA Plan or the management or disposition of the assets of an ERISA Plan, or who renders investment advice for a fee or other compensation to an ERISA Plan, is generally considered to be a fiduciary of the ERISA Plan. In considering an investment in our common units, among other things, consideration should be given to:

• whether the investment is prudent under Section 404(a)(1)(B) of ERISA and any other applicable Similar Laws;

• whether, in making the investment, the employee benefit plan will satisfy the diversification requirements of Section 404(a)(1)(C) of ERISA and any other applicable Similar Laws;

• whether the investment is permitted under the terms of the applicable documents governing the Plan;

• whether making the investment will comply with the delegation of control and prohibited transaction provisions under Section 406 of ERISA, Section 4975 of the Internal Revenue Code and any other applicable Similar Laws (please read the discussion under “—Prohibited Transaction Issues” below);

• whether in making the investment, the Plan will be considered to hold, as plan assets, (1) only the investment in our common units or (2) an undivided interest in our underlying assets (please read the discussion under “—Plan Asset Issues” below); and

• whether the investment will result in recognition of unrelated business taxable income by the employee benefit plan and, if so, the potential after-tax investment return. Please read “Material Federal Income Tax Consequences—Tax-Exempt Organizations and Other Investors.”

The person with investment discretion with respect to the assets of a 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 Plan.

Governmental plans (as defined in Section 3(32) of ERISA) and certain church plans (as defined in Section 3(33) of ERISA) and non-U.S. plans (as defined in Section 4(b)(4) of ERISA), while generally not subject to the fiduciary responsibility provisions of ERISA or the provisions of Section 4975 of the Internal Revenue Code,

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may nevertheless be subject to local, state or other federal or non-U.S. laws that are substantially similar to ERISA and the Internal Revenue Code. Fiduciaries of any such Plans should consult with their counsel before acquiring our common units.

Prohibited Transaction Issues

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

Plan Asset Issues

In addition to considering whether the purchase of our common units is a prohibited transaction, a fiduciary of a Plan should consider whether the 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 prohibited transaction rules, as well as the prohibited transaction rules of the Internal Revenue Code and any other applicable Similar Laws.

The Department of Labor regulations provide guidance with respect to whether the assets of an entity in which Plans acquire equity interests would be deemed “plan assets” under certain circumstances. Under these regulations, an entity’s underlying assets generally would not be considered to be “plan assets” if, among other things:

(1) the equity interests acquired by employee benefit plans are publicly offered securities—i.e., the equity interests are part of a class of securities that are widely held by 100 or more investors independent of the issuer and each other, “freely transferable” (as defined in the applicable Department of Labor regulations) and either part of a class of securities registered pursuant to certain provisions of the federal securities laws or sold to the plan as part of a public offering under certain conditions;

(2) the entity is an “operating company”—i.e., it is primarily engaged in the production or sale of a product or service other than the investment of capital either directly or through a majority-owned subsidiary or subsidiaries; or

(3) there is no significant investment by benefit plan investors, which is defined to mean that, immediately after the most recent acquisition of an equity interest in any entity by an employee benefit plan, less than 25% of the total value of each class of equity interest, disregarding certain interests held by our general partner, its affiliates and certain other persons, is held by the employee benefit plans and IRAs referred to above and entities whose underlying assets are considered to include “plan assets” of any such plans or IRAs.

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 (1) and (2) above and may also satisfy the requirements in (3) above (although we do not monitor the level of investment by benefit plan investors as required for compliance with (3)).

The foregoing discussion of issues arising for employee benefit plan investments under ERISA, the Internal Revenue 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. Plan fiduciaries contemplating a purchase of our common units should consult with their own counsel regarding the consequences of such purchase under ERISA, the Internal Revenue Code and Similar Laws in light of the serious penalties, excise taxes and liabilities imposed on persons who engage in prohibited transactions or other violations.

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UNDERWRITING

Barclays Capital Inc. and Robert W. Baird & Co. Incorporated are acting as the representatives of the underwriters and the joint book-running managers of this offering. Under the terms of an underwriting agreement, which will be filed as an exhibit to the registration statement, each of the underwriters named below has severally agreed to purchase from us the respective number of common units shown opposite its name below:

Underwriters	Number of Common Units
Barclays Capital Inc.
Robert W. Baird & Co. Incorporated
Total

The underwriting agreement provides that the underwriters’ obligation to purchase common units depends on the satisfaction of the conditions contained in the underwriting agreement including:

• the obligation to purchase all of the common units offered hereby (other than those common units covered by their option to purchase additional common units as described below), if any of the common units are purchased;

• the representations and warranties made by us to the underwriters are true;

• there is no material change in our business or the financial markets; and

• we deliver customary closing documents to the underwriters.

Commissions and Expenses

The following table summarizes the underwriting discounts and commissions we will pay to the underwriters. These amounts are shown assuming both no exercise and full exercise of the underwriters’ option to purchase additional common units. The underwriting fee is the difference between the initial price to the public and the amount the underwriters pay to us for the common units.

	No Exercise	Full Exercise
Per common unit	$	$
Total	$	$

In addition, we will pay an aggregate structuring fee of     % to             for evaluation, analysis and structuring of this offering.

The representatives have advised us that the underwriters propose to offer the common units directly to the public at the public offering price on the cover of this prospectus and to selected dealers, which may include the underwriters, at such offering price less a selling concession not in excess of $         per common unit. After the offering, the representatives may change the offering price and other selling terms.

The expenses of the offering that are payable by us are estimated to be approximately $         (excluding underwriting discounts, structuring fees and commissions).

Option to Purchase Additional Common Units

We have granted the underwriters an option exercisable for 30 days after the date of this prospectus to purchase, from time to time, in whole or in part, up to an aggregate of             additional common units from us at

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the public offering price less underwriting discounts and commissions. This option may be exercised to the extent the underwriters sell more than common units in connection with this offering. To the extent that this option is exercised, each underwriter will be obligated, subject to certain conditions, to purchase its pro rata portion of these additional common units based on the underwriter’s percentage underwriting commitment in the offering as indicated in the table at the beginning of this Underwriting Section.

Lock-Up Agreements

We, Noble, our general partner, the directors and executive officers of our general partner and holders of more than 5% of our outstanding common units, have agreed that, for a period of 180 days after the date of this prospectus, we and they will not directly or indirectly, without the prior written consent of Barclays Capital Inc., (1) offer for sale, sell, pledge, or otherwise dispose of (or enter into any transaction or device that is designed to, or could be expected to, result in the disposition by any person at any time in the future of) any common units (including, without limitation, common units that may be deemed to be beneficially owned by us or them in accordance with the rules and regulations of the SEC and common units that may be issued upon exercise of any options or warrants) or securities convertible into or exercisable or exchangeable for common units (other than the common units issued pursuant to employee benefit plans or other employee compensation plans existing on the date of this prospectus), or sell or grant options, rights or warrants with respect to any common units or securities convertible into or exchangeable for common units (other than the grant of options pursuant to option plans existing on the date of this prospectus), (2) enter into any swap or other derivatives transaction that transfers to another, in whole or in part, any of the economic benefits or risks of ownership of common units, whether any such transaction described in clause (1) or (2) above is to be settled by delivery of common units or other securities, in cash or otherwise, (3) make any demand for or exercise any right or file or cause to be filed a registration statement, including any amendments thereto, with respect to the registration of any common units or securities convertible, exercisable or exchangeable into common units or any of our other securities (other than any registration statement on Form S-8), or (4) publicly disclose the intention to do any of the foregoing.

Barclays Capital Inc., 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. When determining whether or not to release common units and other securities from lock-up agreements, Barclays Capital Inc. will consider, among other factors, the holder’s reasons for requesting the release, the number of common units and other securities for which the release is being requested and market conditions at the time.

As described below under “—Directed Unit Program,” any participants in the Directed Unit Program will be subject to a 180-day lock up with respect to any common units sold to them pursuant to that program. This lock up will have similar restrictions as the lock-up agreement described above. Any common units sold in the Directed Unit Program to our directors or officers shall be subject to the lock-up agreement described above.

Directed Unit Program

At our request, the underwriters have reserved up to     % of the common units for sale at the initial public offering price to persons who are directors, officers or employees of our general partner and its affiliates and certain other persons associated with us, as designated by us, through a directed unit program. The number of common units available for sale to the general public will be reduced by the number of directed units purchased by participants in the program. Except for certain of the officers and directors of our general partner who have entered into lock-up agreements, each person buying common units through the directed unit program has agreed that, for a period of 180 days from the date of this prospectus, he or she will not, without the prior written consent of                 , dispose of or hedge any common units or any securities convertible into or exchangeable for our common units with respect to units purchased in the program. For certain officers and directors of our general partner purchasing common units through the directed unit program, the lock-up agreements described above shall govern with respect to their purchases.                 in its sole discretion may release any of the securities subject to these lock-up agreements at any time, which, in the case of officers and directors of our

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general partner, shall be with notice. Any directed units not purchased will be offered by the underwriters to the general public on the same basis as all other common units offered. We have agreed to indemnify the underwriters against certain liabilities and expenses, including liabilities under the Securities Act, in connection with the sales of the directed units.

Offering Price Determination

Prior to this offering, there has been no public market for our common units. The initial public offering price was negotiated between the representatives and us. In determining the initial public offering price of our common units, the representatives considered:

• the history and prospects for the industry in which we compete;

• our financial information;

• the ability of our management and our business potential and earning prospects;

• the prevailing securities markets at the time of this offering; and

• the recent market prices of, and the demand for, publicly traded common units of generally comparable companies.

Indemnification

We have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act, and to contribute to payments that the underwriters may be required to make for these liabilities.

Stabilization, Short Positions and Penalty Bids

The representatives may engage in stabilizing transactions, short sales and purchases to cover positions created by short sales, and penalty bids or purchases for the purpose of pegging, fixing or maintaining the price of the common units, in accordance with Regulation M under the Exchange Act:

• Stabilizing transactions permit bids to purchase the underlying security so long as the stabilizing bids do not exceed a specified maximum.

• A short position involves a sale by the underwriters of common units in excess of the number of common units the underwriters are obligated to purchase in the offering, which creates the syndicate short position. This short position may be either a covered short position or a naked short position. In a covered short position, the number of common units involved in the sales made by the underwriters in excess of the number of common units they are obligated to purchase is not greater than the number of common units that they may purchase by exercising their option to purchase additional common units. In a naked short position, the number of common units involved is greater than the number of common units in their option to purchase additional common units. The underwriters may close out any short position by either exercising their option to purchase additional common units or purchasing common units in the open market. In determining the source of common units to close out the short position, the underwriters will consider, among other things, the price of common units available for purchase in the open market as compared to the price at which they may purchase common units through their option to purchase additional common units. A naked short position is more likely to be created if the underwriters are concerned that there could be downward pressure on the price of the common units in the open market after pricing that could adversely affect investors who purchase in the offering.

• Syndicate covering transactions involve purchases of common units in the open market after the distribution has been completed in order to cover syndicate short positions.

• Penalty bids permit the representatives to reclaim a selling concession from a syndicate member when common units originally sold by the syndicate member is purchased in a stabilizing or syndicate covering transaction to cover syndicate short positions.

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• These stabilizing transactions, syndicate covering transactions and penalty bids may have the effect of raising or maintaining the market price of the common units or preventing or retarding a decline in the market price of the common units. As a result, the price of the common units may be higher than the price that might otherwise exist in the open market. These transactions may be effected on the NYSE or otherwise and, if commenced, may be discontinued at any time.

Neither we nor any of the underwriters make any representation or prediction as to the direction or magnitude of any effect that the transactions described above may have on the price of the common units. In addition, neither we nor any of the underwriters make any representation that the representatives will engage in these stabilizing transactions or that any transaction, once commenced, will not be discontinued without notice.

Listing on the New York Stock Exchange

We intend to apply for listing of our common units on the NYSE under the symbol “NBLX.”

Stamp Taxes

If you purchase common units offered in this prospectus, you may be required to pay stamp taxes and other charges under the laws and practices of the country of purchase, in addition to the offering price listed on the cover page of this prospectus.

Other Relationships

The underwriters and certain of their 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. The underwriters and certain of their affiliates have, from time to time, performed, and may in the future perform, various commercial and investment banking and financial advisory services for us and our affiliates, including Noble, and to persons and entities with relationships with us and our affiliates, for which they received or may in the future receive customary fees and expenses.

In the ordinary course of their various business activities, the underwriters and certain of 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 such investment and securities activities may involve securities or instruments of the issuer or its affiliates. If the underwriters or their respective affiliates have a lending relationship with us, certain of those underwriters or their affiliates routinely hedge, and certain other of those underwriters or their affiliates may hedge, their credit exposure to us consistent with their customary risk management policies. Typically, the underwriters and their affiliates would hedge such exposure by entering into transactions which consist of either the purchase of credit default swaps or the creation of short positions in our securities or the securities of our affiliates, including potentially the common units offered hereby. Any such credit default swaps or short positions could adversely affect future trading prices of the common units offered hereby. The underwriters and certain of their affiliates may also communicate independent investment recommendations, market color or trading ideas 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.

Direct Participation Plan Requirements

Because FINRA views the common units offered hereby as interests in a direct participation program, the offering is being made in compliance with FINRA Rule 2310. Investor suitability with respect to the common units should be judged similarly to the suitability with respect to other securities that are listed for trading on a national securities exchange.

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Selling Restrictions

This prospectus does not constitute an offer to sell to, or a solicitation of an offer to buy from, anyone in any country or jurisdiction (i) in which such an offer or solicitation is not authorized, (ii) in which any person making such offer or solicitation is not qualified to do so or (iii) in which any such offer or solicitation would otherwise be unlawful. No action has been taken that would, or is intended to, permit a public offer of the common units or possession or distribution of this prospectus or any other offering or publicity material relating to the common units in any country or jurisdiction (other than the United States) where any such action for that purpose is required. Accordingly, each underwriter has undertaken that it will not, directly or indirectly, offer or sell any common units or have in its possession, distribute or publish any prospectus, form of application, advertisement or other document or information in any country or jurisdiction except under circumstances that will, to the best of its knowledge and belief, result in compliance with any applicable laws and regulations and all offers and sales of common units by it will be made on the same terms.

Singapore

This prospectus has not been and will not be 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 under Section 274 of the Securities and Futures Act, Chapter 289 of Singapore, or SFA, (ii) to a relevant person pursuant to Section 275(1), or any person pursuant to Section 275(1A), 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.

Where the common units are subscribed or purchased under Section 275 of the SFA by a relevant person which is:

(1) 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 share capital of which is owned by one or more individuals, each of whom is an accredited investor; or

(2) a trust (where the trustee is not an accredited investor) whose sole purpose is to hold investments and each beneficiary of the trust is an individual who is an accredited investor, securities (as defined in Section 239(1) of the SFA) of that corporation or the beneficiaries’ rights and interest (howsoever described) in that trust shall not be transferred within six months after that corporation or that trust has acquired the common units pursuant to an offer made under Section 275 of the SFA except:

(a) to an institutional investor or to a relevant person defined in Section 275(2) of the SFA, or to any person arising from an offer referred to in Section 275(1A) or Section 276(4)(i)(B) of the SFA;

(b) where no consideration is or will be given for the transfer;

(c) where the transfer is by operation of law;

(d) as specified in Section 276(7) of the SFA; or

(e) as specified in Regulation 32 of the Securities and Futures (Offers of Investments) (Shares and Debentures) Regulations 2005 of Singapore.

Hong Kong

Our common units may not be offered or sold in Hong Kong by means of this prospectus or any other document other than to (a) professional investors as defined in the Securities and Futures Ordinance of Hong Kong (Cap. 571, Laws of Hong Kong), or SFO, and any rules made under the SFO, or (b) in other circumstances

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which do not result in this prospectus being deemed to be a “prospectus,” as defined in the Companies Ordinance of Hong Kong (Cap. 32, Laws of Hong Kong), or CO, or which do not constitute an offer to the public within the meaning of the CO or the SFO; and no person has issued or had in possession for the purposes of issue, or will issue or has in possession for the purposes of issue, whether in Hong Kong or elsewhere, any advertisement, invitation or document relating to our common units 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 our 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 SFO.

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VALIDITY OF THE COMMON UNITS

The validity of the common units and certain tax and other legal matters will be passed upon for us by Andrews Kurth LLP, Houston, Texas. Certain legal matters in connection with our common units offered hereby will be passed upon for the underwriters by Vinson & Elkins L.L.P., Houston, Texas.

EXPERTS

The financial statements of Noble Midstream Partners LP Predecessor as of December 31, 2014 and 2013, and for the years then ended, appearing in this prospectus and registration statement have been audited by KPMG LLP, independent registered public accounting firm, as set forth in their report thereon appearing elsewhere herein, and are included in reliance upon such report given on the authority of such firm as experts in accounting and auditing.

The balance sheet of Noble Midstream Partners LP at July 17, 2015, appearing in this prospectus and registration statement has been audited by KPMG LLP, independent registered public accounting firm, as set forth in their report thereon appearing elsewhere herein, and is included in reliance upon such report given on the authority of such firm as experts in accounting and auditing.

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WHERE YOU CAN FIND ADDITIONAL INFORMATION

We have filed with the SEC a registration statement on Form S-1 relating to the common units offered by this prospectus. This prospectus, which constitutes a part of the registration statement, does not contain all of the information set forth in the registration statement. For further information regarding us and the common units offered by this prospectus, we refer you to the full registration statement, including its exhibits and schedules, filed under the Securities Act. The registration statement, of which this prospectus constitutes a part, including its exhibits and schedules, may be inspected and copied at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. Copies of the materials may also be obtained from the SEC at prescribed rates by writing to the Public Reference Room. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330.

The SEC maintains a website at www.sec.gov that contains reports, information statements and other information regarding issuers that file electronically with the SEC. Our registration statement, of which this prospectus constitutes a part, can be downloaded from the SEC’s website.

After the completion of this offering, we will file with or furnish to the SEC periodic reports and other information. These reports and other information may be inspected and copied at the Public Reference Room maintained by the SEC or obtained from the SEC’s website as provided above. Following the completion of this offering, our website will be located at www.NBLMidstream.com. We intend 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 on our website or any other website is not incorporated by reference into this prospectus and does not constitute a part of this prospectus.

We intend to furnish or make available to our unitholders annual reports containing our audited financial statements prepared in accordance with GAAP. We also intend to furnish or make available to our unitholders quarterly reports containing our unaudited interim financial information, including the information required by Form 10-Q, for the first three fiscal quarters of each fiscal year.

Noble is subject to the information requirements of the Exchange Act and, in accordance therewith, files reports and other information with the SEC. You may read Noble’s filings on the SEC’s website and at the Public Reference Room described above or Noble’s website at www.nobleenergyinc.com. Noble’s common stock trades on the NYSE under the symbol “NBL.” Information on Noble’s website is not incorporated by reference into this prospectus and does not constitute a part of this prospectus.

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FORWARD-LOOKING STATEMENTS

This prospectus contains forward-looking statements. Statements that are predictive in nature, that depend upon or refer to future events or conditions or that include the words “believe,” “expect,” “anticipate,” “intend,” “estimate” and other expressions that are predictions of or indicate future events and trends and that do not relate to historical matters identify forward-looking statements. Our forward-looking statements include statements about our business strategy, our industry, our future profitability, our expected capital expenditures and the impact of such expenditures on our performance, the costs of being a publicly traded partnership and our capital programs. All statements in this prospectus about our forecast of distributable cash flow and our forecasted results for the twelve months ending September 30, 2016 constitute forward-looking statements.

A forward-looking statement may include a statement of the assumptions or bases underlying the forward-looking statement. We believe that we have chosen these assumptions or bases in good faith and that they are reasonable. 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 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:

• Noble’s ability to meet their drilling and development plan in the DJ Basin;

• changes in general economic conditions;

• competitive conditions in our industry;

• actions taken by third-party operators, gatherers, processors and transporters;

• the demand for crude oil and natural gas gathering and processing services;

• our ability to successfully implement our business plan;

• our ability to complete internal growth projects on time and on budget;

• the price and availability of debt and equity financing;

• the availability and price of crude oil and natural gas to the consumer compared to the price of alternative and competing fuels;

• competition from the same and alternative energy sources;

• energy efficiency and technology trends;

• operating hazards and other risks incidental to our midstream services;

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

• interest rates;

• labor relations;

• defaults by Noble under our gathering and processing agreements;

• changes in availability and cost of capital;

• changes in our tax status;

• the effect of existing and future laws and government regulations;

• the effects of future litigation; and

• certain factors discussed elsewhere in this prospectus.

You should not place undue reliance on our forward-looking statements. Although forward-looking statements reflect our good faith beliefs at the time they are made, forward-looking statements involve known

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and unknown risks, uncertainties and other factors, including the factors described under “Risk Factors,” which may cause our actual results, performance or achievements to differ materially from anticipated future results, performance or achievements expressed or implied by such forward-looking statements. We undertake no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events, changed circumstances or otherwise, unless required by law.

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INDEX TO FINANCIAL STATEMENTS

Noble Midstream Partners LP

Unaudited Pro Forma Condensed Combined Financial Statements
Introduction	F-2
Unaudited Pro Forma Condensed Combined Statement of Operations for the Year Ended December 31, 2014	F-4
Unaudited Pro Forma Condensed Combined Statement of Operations for the Three Months Ended March  31, 2015	F-5
Unaudited Pro Forma Condensed Combined Balance Sheet as of March 31, 2015	F-6
Notes to Unaudited Pro Forma Condensed Combined Financial Statements	F-7
Noble Midstream Partners LP Predecessor
Historical Financial Statements
Combined Statements of Operations for the Three Months Ended March 31, 2015 and 2014	F-9
Combined Balance Sheets as of March 31, 2015 (Supplemental Pro Forma), March  31, 2015 (Historical) and December 31, 2014	F-10
Combined Statements of Changes in Net Parent Investment as of December 31, 2014 and March  31, 2015	F-11
Combined Statements of Cash Flows for the Three Months Ended March 31, 2015 and 2014	F-12
Notes to Unaudited Combined Financial Statements	F-13
Report of Independent Registered Public Accounting Firm	F-20
Combined Statements of Operations for the Years Ended December 31, 2014 and 2013	F-21
Combined Balance Sheets as of December 31, 2014 and 2013	F-22
Combined Statements of Changes in Net Parent Investment as of December 31, 2014 and 2013	F-23
Combined Statements of Cash Flows for the Years Ended December 31, 2014 and 2013	F-24
Notes to Combined Financial Statements	F-25
Noble Midstream Partners LP
Report of Independent Registered Public Accounting Firm	F-34
Balance Sheet as of July 17, 2015	F-35
Notes to Balance Sheet	F-36

F-1

NOBLE MIDSTREAM PARTNERS LP

UNAUDITED PRO FORMA CONDENSED COMBINED FINANCIAL STATEMENTS

Introduction

Set forth below are the unaudited pro forma condensed combined balance sheet as of March 31, 2015 and the unaudited pro forma condensed combined statements of operations for the year ended December 31, 2014 and the three months ended March 31, 2015 (together with the notes to the unaudited pro forma condensed combined financial statements, the “pro forma financial statements”) of Noble Midstream Partners LP (the “Partnership”, “we,” “us” or “our”). Our pro forma financial statements have been derived from the historical combined financial statements of Noble Midstream Partners LP Predecessor, our predecessor for accounting purposes (our “Predecessor”), which are included elsewhere in this prospectus.

The Predecessor’s business includes the contributed assets, liabilities and results of operations of (i) crude oil and natural gas gathering systems located in the DJ Basin in northern Colorado, (ii) crude oil treating facilities in the DJ Basin in northern Colorado, (iii) fresh water storage and delivery and saltwater collection, gathering, cleaning, recycling and disposal systems in the DJ Basin in northern Colorado and (iv) a 3.33% non-controlling member interest in White Cliffs Pipeline, L.L.C. also located in the DJ Basin (the “White Cliffs Interest”) (collectively, the “Contributed Businesses”).

We will own and operate the businesses of our Predecessor effective as of the closing of this offering. The contribution of our Predecessor’s business to us will be recorded at historical cost as it is considered to be a reorganization of entities under common control. Upon completion of this offering, we will own controlling interests in the development companies that own our operating assets ranging from     % to     %. The pro forma financial statements have been prepared on the basis that we will be treated as a partnership for U.S. federal income tax purposes.

The pro forma financial statements have been derived from the audited and unaudited historical combined financial statements of our Predecessor. The historical financial statements of the Predecessor are set forth elsewhere in this prospectus, and the pro forma financial statements for 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 therein. The pro forma adjustments are based upon 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 the significant effects of the contemplated transactions and that the pro forma adjustments are factually supportable and give appropriate effect to those estimates and assumptions.

The pro forma adjustments have been prepared as if the transactions to be effected at the closing of the offering had taken place on March 31, 2015, in the case of the unaudited pro forma condensed combined balance sheet, and as of January 1, 2014, in the case of the unaudited pro forma condensed combined statements of operations for the year ended December 31, 2014 and the three months ended March 31, 2015. The pro forma financial statements have been presented for informational purposes only. The pro forma financial statements may not be indicative of the results that actually would have occurred if we had assumed the operations of our Predecessor on the dates indicated, or the results that will be obtained in the future.

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

• Noble’s contribution of the Contributed Businesses to us, including the percentages of the development companies that will operate our assets described under “Certain Relationships and Related Party Transactions—Agreements with our Affiliates in Connection with the Transactions—Contribution Agreement;”

• the recognition of incremental revenues under our commercial agreements;

F-2

• our entry into a new $            million revolving credit facility;

• our entry into an omnibus agreement with Noble;

• the consummation of this offering and our issuance of (i)            common units to the public (assuming the underwriters’ option to purchase additional            common units from us is not exercised) and (ii)              common units,             subordinated units, a non-economic general partner interest in us and all of our incentive distribution rights (“IDRs”) to Noble; and

• the application of the net proceeds of this offering as described in “Use of Proceeds.”

The pro forma financial statements do not give effect to an estimated $            million in incremental general and administrative expenses that we expect to incur annually as a result of being a publicly traded partnership, including costs associated with annual and quarterly reports to unitholders, preparation and distribution of our financial statements, tax return and Schedule K-1 preparation and distribution expenses, investor relations activities, registrar and transfer agent fees, incremental director and officer liability insurance premiums and independent director compensation. The pro forma financial statements also do not give effect to variable general and administrative costs we will incur under the omnibus agreement that we will enter into with Noble as of the closing of this offering. As a result, the pro forma financial statements may not be indicative of the results that actually would have occurred if the matters described above had occurred on the dates indicated or that would be obtained in the future.

F-3

Noble Midstream Partners LP

Unaudited Pro Forma Condensed Combined Statement of Operations

Year Ended December 31, 2014

(in thousands)

	Historical			Pro Forma Adjustments			Pro Forma
Revenues
Revenues—Related Party	$	2,086		$	(a	)	$
Income from Investments		3,798
Total Revenues		5,884			(a	)
Expenses
Direct Operating		8,538
Depreciation, Depletion and Amortization		11,315
General and Administrative		6,734			(b	)
Total Expenses		26,587
Operating Loss		(20,703	)
Interest Expense, Net of Amount Capitalized		3,566			(c	)
Loss Before Income Taxes		(24,269	)
Income Tax Benefit		(9,178	)		(d	)
Net Loss		(15,091	)
Net loss attributable to non-controlling interests		—			(e	)
Net loss attributable to Noble Midstream Partners LP	$	(15,091	)	$			$
Pro forma general partner interest in net income attributable to Noble Midstream Partners LP
Pro forma limited partners’ interest in net income attributable to Noble 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

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

F-4

Noble Midstream Partners LP

Unaudited Pro Forma Condensed Combined Statement of Operations

Three Months Ended March 31, 2015

(in thousands)

	Historical		Pro Forma Adjustments			Pro Forma
Revenues
Revenues—Related Party	$	12,852	$			$
Income from Investments		1,236
Total Revenues		14,088
Expenses
Direct Operating		2,670
Depreciation, Depletion and Amortization		1,345
General and Administrative		545		(b	)
Total Expenses		4,560
Operating Income		9,528
Interest Expense, Net of Amount Capitalized		515		(c	)
Income Before Income Taxes		9,013
Income Tax Provision		3,409		(d	)
Net Income		5,604
Net Income Attributable to Non-Controlling Interests		—		(e	)
Net Income Attributable to Noble Midstream Partners LP	$	5,604	$			$
Pro forma general partner interest in net income attributable to Noble Midstream Partners LP
Pro forma limited partners’ interest in net income attributable to Noble 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

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

F-5

Noble Midstream Partners LP

Unaudited Pro Forma Condensed Combined Balance Sheet

As of March 31, 2015

(in thousands)

	Historical			Pro Forma Adjustments		Pro Forma
ASSETS
Current Assets
Cash and Cash Equivalents	$	9,930		$	(f)	$
Accounts Receivable—Related Party		5,112			(g)
Deferred Tax Asset		11,266
Other Current Assets		104
Total Current Assets		26,412
Property, Plant and Equipment
Total Property, Plant and Equipment, Gross		237,745
Less: Accumulated Depreciation		(17,384	)
Total Property, Plant and Equipment, Net		220,361
Investments		11,590
Total Assets	$	258,363		$		$
LIABILITIES AND NET PARENT INVESTMENT
Current Liabilities
Accounts Payable—Related Party	$	509		$		$
Accounts Payable—Trade		12,252
Other Current Liabilities		204
Total Current Liabilities		12,965
Long-Term Debt		—
Deferred Income Taxes, Noncurrent		4,753
Asset Retirement Obligations		4,833
Total Liabilities		19,980
Net Parent Investment/Partners’ Capital
Net Parent Investment		235,812			(h)
Common Unitholders—Public		—			(i)
Common Unitholders—Noble		—			(h)
Subordinated Unitholders—Noble		—			(h)
General Partner—Noble		—			(h)
Non-controlling Interest—Noble		—			(h)
Total Net Parent Investment/Partners’ Capital		235,812
Total Liabilities and Net Parent Investment	$	258,363		$		$

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

F-6

Noble Midstream Partners LP

Notes to Unaudited Pro Forma Condensed Financial Statements

1. Pro Forma Adjustments and Assumptions

The pro forma adjustments are based on currently available information and certain estimates and assumptions and, therefore, the actual effects of these transactions will differ from the pro forma adjustments. We have only included adjustments that are directly attributable to the transactions, factually supportable and, with respect to the statements of operations, expected to have a continuing impact on the combined results. A general description of these transactions and adjustments is provided as follows:

(a) Represents the pro forma adjustment to revenues associated with the Partnership’s execution of new long-term, fixed-fee commercial agreements with Noble. The increase to revenue is calculated using the fees under the commercial agreements applied to the historical volumes during the year ended December 31, 2014.

Midstream Service	Rate	Average Daily Throughput/Well  Count for the Year Ended December 31, 2014	Pro Forma Revenue (in millions)
Natural Gas Gathering	$             per MMBtu	Bbtu/d	$
Crude Oil Gathering	$             per barrel	MBbl/d	$
Crude Oil Treating	$                 /     per well Vertical/Horizontal		$
Saltwater Services	$             per barrel	MBbl/d	$
Fresh Water Delivery	$             per barrel	MBbl/d	$

(b) Represents the fixed-fee portion of additional general and administrative expenses incurred under our omnibus agreement.

(c) Represents the pro forma adjustment to interest expense associated with our allocated portion of Noble’s interest expense and the amortization of origination fees and the commitment fee associated with the new revolving credit facility over the five year expected term of the facility. As of the date of the offering, we do not expect to draw on the revolving credit facility, and as such, no further pro forma adjustments for interest expense are included.

(d) We will not be subject to income taxes as a publicly traded partnership. As such, this adjustment removes our historical taxes.

(e) Represents the    %,    %,    %,    % and    % non-controlling interests in NBLX DevCo I LP, NBLX DevCo II LP, NBLX DevCo III LP, NBLX DevCo IV LP and NBLX DevCo V LP, respectively, retained by Noble, that have been calculated for each of the periods presented.

F-7

Noble Midstream Partners LP

Notes to Unaudited Pro Forma Condensed Financial Statements

(f) Represents the net adjustments to cash and cash equivalents, as follows (in thousands):

	March 31, 2015
Gross proceeds from initial public offering	$
Underwriters’ discount and fees
Expenses and costs of initial public offering
Payment of debt issuance costs (see note c)
Distribution of proceeds to Noble
Cash and cash equivalents pro forma adjustment	$

(g) Represents the distribution of the remaining IPO proceeds of $            to Noble.

(h) Represents the elimination of Noble’s net investment in us at March 31, 2015 following Noble’s contribution to us of    %,    %,    %,    % and    % controlling interests in NBLX DevCo I LP, NBLX DevCo II LP, NBLX DevCo III LP, NBLX DevCo IV LP and NBLX DevCo V LP, respectively.

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

	March 31, 2015
Gross proceeds from initial public offering (see note f)	$
Underwriters’ discount and fees (see note f)
Expenses and costs of initial public offering (see note f)
	$

2. Pro Forma Net Income per Unit

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, we assumed (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 us. All units were assumed to have been outstanding since January 1, 2014. 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.

F-8

Noble Midstream Partners LP Predecessor

Combined Statements of Operations

(in thousands)

(unaudited)

	Three Months Ended March 31,
	2015		2014
Revenues
Midstream Services—Related Party	$	12,852	$	513
Income from Investments		1,236		773
Total Revenues		14,088		1,286
Costs and Expenses
Direct Operating		2,670		2,318
Depreciation, Depletion and Amortization		1,345		2,250
General and Administrative		545		1,596
Total Operating Expenses		4,560		6,164
Operating Income (Loss)		9,528		(4,878	)
Other Expense
Interest Expense, Net of Amount Capitalized		515		472
Total Other Expense		515		472
Income (Loss) Before Income Taxes		9,013		(5,350	)
Income Tax Provision (Benefit)		3,409		(2,023	)
Net Income (Loss)	$	5,604	$	(3,327	)

Supplemental pro forma (unaudited) basic and diluted income (loss) per
limited partner unit (See Note 10)

Common units

Subordinated units

The accompanying notes are an integral part of these unaudited combined financial statements

F-9

Noble Midstream Partners LP Predecessor

Combined Balance Sheets

(in thousands)

(unaudited)

	Supplemental Pro Forma March 31, 2015			March 31, 2015			December 31, 2014
ASSETS
Current Assets
Cash and Cash Equivalents	$	9,930		$	9,930		$	—
Accounts Receivable—Related Party		5,112			5,112			—
Deferred Tax Asset		11,266			11,266			—
Other Current Assets		104			104			—
Total Current Assets		26,412			26,412			—
Property, Plant and Equipment
Total Property, Plant and Equipment, Gross		237,745			237,745			211,586
Accumulated Depreciation, Depletion and Amortization		(17,384	)		(17,384	)		(16,073	)
Total Property, Plant and Equipment, Net		220,361			220,361			195,513
Investments		11,590			11,590			11,077
Deferred Tax Asset		—			—			9,922
Total Assets	$	258,363		$	258,363		$	216,512
LIABILITIES AND NET PARENT INVESTMENT
Current Liabilities
Accounts Payable—Related Party	$	509		$	509		$	—
Accounts Payable—Trade		12,252			12,252			—
Due to Affiliate		—			—			—
Other Current Liabilities		204			204			—
Total Current Liabilities		12,965			12,965			—
Deferred Income Taxes, Noncurrent		4,753			4,753			—
Asset Retirement Obligations		4,833			4,833			2,839
Total Liabilities		22,551			22,551			2,839
Commitments and Contingencies
Total Net Equity—Net Parent Investment		235,812			235,812			213,673
Total Liabilities and Net Parent Investment	$	258,363		$	258,363		$	216,512

The accompanying notes are an integral part of these unaudited combined financial statements

F-10

Noble Midstream Partners LP Predecessor

Combined Statements of Changes in Net Parent Investment

(in thousands)

(unaudited)

	Total Net Equity—Net Parent Investment
Balance at December 31, 2014	$	213,673
Net Income		5,604
Transactions with Parent, Net		16,535
Balance at March 31, 2015	$	235,812

The accompanying notes are an integral part of these unaudited combined financial statements

F-11

Noble Midstream Partners LP Predecessor

Combined Statements of Cash Flows

(in thousands)

(unaudited)

	Three Months Ended March 31,
	2015			2014
Cash Flows from Operating Activities
Net Income (Loss)	$	5,604		$	(3,327	)
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by (Used in) Operating Activities
Depreciation, Depletion and Amortization		1,345			2,250
Deferred Income Tax Provision (Benefit)		3,409			(2,023	)
Stock Based Compensation		57			106
Changes in Operating Assets and Liabilities
(Increase) in Accounts Receivable—Related Party		(5,112	)		—
(Increase) Decrease in Other Current Assets		(104	)		—
(Decrease) Increase in Accounts Payable		2,889			—
Other Operating Assets and Liabilities, Net		204			—
Net Cash Provided by (Used in) Operating Activities		8,292			(2,994	)
Cash Flows From Investing Activities
Additions to Property, Plant and Equipment		(19,371	)		(15,702	)
Additions to Investments		(854	)		—
Distributions from Investments		341			114
Net Cash Used in Investing Activities		(19,884	)		(15,588	)
Cash Flows From Financing Activities
Contributions from Parent, Net		21,522			18,582
Net Cash Provided by Financing Activities		21,522			18,582
Increase in Cash and Cash Equivalents		9,930			—
Cash and Cash Equivalents at Beginning of Period		—			—
Cash and Cash Equivalents at End of Period	$	9,930		$	—

The accompanying notes are an integral part of these unaudited combined financial statements

F-12

Noble Midstream Partners LP Predecessor

Notes to the Unaudited Combined Financial Statements

Note 1. Description of Business and Basis of Presentation

These combined financial statements constitute the contributed business of our accounting predecessor (the “Predecessor,” “we” or “our”) from Noble Energy, Inc. (“Noble”) to a newly formed limited partnership, Noble Midstream Partners LP (the “Partnership”), and have been prepared in connection with the initial public offering (the “Offering”) of common units representing limited partner interests in the Partnership.

The Predecessor’s business includes the contributed assets, liabilities and results of operations of (i) crude oil and natural gas gathering systems located in the DJ Basin in northern Colorado, (ii) crude oil treating facilities in the DJ Basin in northern Colorado, (iii) fresh water storage and delivery and saltwater collection in the DJ Basin in northern Colorado, gathering, cleaning, recycling and disposal systems in the DJ Basin in northern Colorado and (iv) a 3.33% non-controlling member interest in White Cliffs Pipeline, L.L.C. also located in the DJ Basin (the “White Cliffs Interest”) (collectively, the “Contributed Businesses”).

The Contributed Businesses were operated and held by a wholly owned subsidiary of Noble during the periods presented in the accompanying combined financial statements. It is anticipated that controlling interests in the Contributed Businesses will be transferred by Noble to the Partnership in connection with the Offering.

The combined financial statements of the Predecessor have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) on the basis of Noble’s historical ownership of the Contributed Businesses.

The accompanying combined statements of operations include expense allocations for certain functions historically performed by Noble but not historically allocated to the Contributed Businesses, including allocations of general corporate services, such as treasury, accounting, human resources and legal services. These allocations were based primarily on direct usage when identifiable or capital expenditures or other relevant allocations during the respective periods. We believe the assumptions underlying the accompanying combined financial statements, including the assumptions regarding allocation of expenses from Noble, are reasonable. Nevertheless, the accompanying combined financial statements may not include all of the expenses that would have been incurred and may not reflect our results of operations, financial position and cash flows had we been a stand-alone company during the periods presented. Because a direct ownership relationship did not exist among the businesses comprising the Predecessor, the net investment in the Predecessor is shown as net parent investment, in lieu of owner’s equity, in the combined financial statements. No goodwill is included in our combined financial statements as none of the goodwill held by Noble is associated with the historical basis of the Contributed Businesses.

Noble used a centralized approach to the cash management and financing of the Predecessor’s operations prior to January 1, 2015. The Predecessor had no bank accounts prior to January 1, 2015 and, as such, the cash generated by our operations was directly received by Noble, and Noble funded our operating and investing activities as needed. Accordingly, the cash and cash equivalents held by Noble were not allocated to us prior to January 1, 2015. We have reflected cash management and financing activities performed by Noble as a component of net parent investment on our accompanying combined balance sheet as of December 31, 2014, and as contributions from parent, net on our accompanying unaudited combined statements of cash flows for the three months ended March 31, 2014.

Note 2. Summary of Significant Accounting Policies

Use of Estimates

The preparation of financial statements in conformity with GAAP requires us to make a number of estimates and assumptions relating to the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during

F-13

Noble Midstream Partners LP Predecessor

Notes to the Unaudited Combined Financial Statements

the reporting period. Items subject to estimates and assumptions include the useful lives of property and equipment, obligations for environmental liabilities, allocations of expenses from Noble, deferred tax assets and liabilities, among others. Although management believes these amounts are reasonable, actual results could differ from these estimates.

Cash and Cash Equivalents

For purposes of reporting cash flows, cash and cash equivalents include unrestricted cash on hand and investments with original maturities of three months or less at the time of purchase.

Property, Plant and Equipment

Property, plant and equipment primarily consists of gathering pipelines, facilities and related equipment, which are stated at the lower of historical cost less accumulated depreciation, or fair value, if impaired. We capitalize construction-related direct labor, material costs and the interest related to construction. Maintenance and repair costs are expensed as incurred.

Prior to January 1, 2015, certain assets were accounted for under the successful efforts method of accounting within Noble’s accounting policies. Under this method, costs to acquire mineral interests in crude oil and natural gas properties, drill and equip exploratory wells that find proved reserves, and drill and equip development wells are capitalized. Capitalized costs of producing crude oil and natural gas properties, along with support equipment and facilities, are amortized to expense by the unit-of-production method based on proved crude oil, natural gas and NGL reserves on a field-by-field basis, as estimated by Noble’s qualified petroleum engineers. Noble’s policy is to use quarter-end reserves and add back current period production to compute quarterly depreciation, depletion and amortization expense. Costs of certain gathering facilities or processing plants serving a number of properties are depreciated using the straight-line method over the useful lives of the assets ranging from three to thirty years. Upon sale or retirement of depreciable or depletable property, the cost and related accumulated depreciation, depletion and amortization are eliminated from the accounts and the resulting gain or loss is recognized.

Although Noble has historically operated the midstream assets in support of the U.S. onshore upstream business as a cost center within the United States reportable segment, beginning in January 2015, Noble began operating the midstream business as a stand-alone business. However, the midstream business will continue to be consolidated by Noble and reported within Noble’s consolidated financial statements. Due to the change in the intended use of these assets, Noble changed the method of depreciation from units-of-production to the preferable straight-line method for future accounting periods. This change is a change in accounting estimate that is effected by a change in accounting principle. When the two are inseparable, the change is accounted for as a change in accounting estimate. Depreciation will be calculated on a straight-line basis prospectively from the first quarter of 2015, the period of change, and in prospective periods. Following this adjustment, our assets will have useful lives ranging from 24 to 30 years. For assets that were converted from the unit-of-production method, their respective asset lives will be 30 years from the date originally placed into service.

Property and equipment included assets under construction of $62.1 million and $42.0 million at March 31, 2015 and December 31, 2014, respectively.

Capitalization of Interest

We capitalize interest costs associated with the development and construction of significant assets or projects to bring them to a condition and location necessary for their intended use. Interest is capitalized using an

F-14

Noble Midstream Partners LP Predecessor

Notes to the Unaudited Combined Financial Statements

interest rate equivalent to the weighted average rate Noble pays on long-term debt. Capitalized interest is included in property, plant and equipment and is depreciated over the life of the asset. Capitalized interest totaled $1.0 million and $0.4 million for the three months ended March 31, 2015 and 2014, respectively.

Investments

We use the cost method of accounting for investments in entities that we do not control or exert significant influence over. We carry the investments at cost on our combined balance sheet and recognize dividends on our combined statement of operations when received. Dividends received in excess of earnings are recorded as a return of capital on the combined balance sheet. We account for our investment in the White Cliffs Interest under the cost method of accounting for investments because we have virtually no influence over partnership operations and financial policies.

Asset Retirement Obligations

Asset retirement obligations (“AROs”) consist of estimated costs of dismantlement, removal, site reclamation and similar activities associated with our equipment and facilities. We recognize the fair value of a liability for an ARO in the period in which it is incurred when we have an existing legal obligation associated with the retirement of our properties that can reasonably be estimated, with the associated asset retirement cost capitalized as part of the carrying cost of the asset. The asset retirement cost is determined at current costs and is inflated into future dollars using an inflation rate that is based on the consumer price index. The future projected cash flows are then discounted to their present value using a credit-adjusted risk-free rate. After initial recording, the liability is increased for the passage of time, with the increase being reflected as accretion expense and included in our depreciation expense in the statement of operations. Subsequent adjustments in the cost estimate are reflected in the liability and the amounts continue to be amortized over the useful life of the related long-lived asset.

Net Parent Investment

In the accompanying combined balance sheets, net parent investment represents Noble’s historical investment in us, our accumulated net results, and the net effect of transactions with, and allocations from, Noble.

Revenue Recognition

Beginning in January 2015, we earn substantially all of our revenues from our commercial agreements we have entered into with Noble. We recognize revenues when persuasive evidence of an arrangement exists, delivery has occurred or services have been rendered, price is fixed or determinable and collectability is reasonably assured.

We recognized related party revenues of $12.9 million and $0.5 million from Noble during the three months ended March 31, 2015 and 2014, respectively.

Income Taxes

We are not a separate taxable entity for U.S. federal and state income tax purposes, and our results are included in the consolidated income tax returns of Noble. The provision for income taxes and income tax assets and liabilities were determined as if we were a stand-alone taxpayer for all periods presented. Deferred income taxes are determined using the liability method and reflect temporary differences between the financial statement carrying amount and income tax basis of assets and liabilities recorded using the currently enacted statutory income tax rate. Regular assessments are made of the likelihood of those deferred tax assets being realized. If it

F-15

Noble Midstream Partners LP Predecessor

Notes to the Unaudited Combined Financial Statements

is more likely than not that some or all of the deferred tax assets will not be realized, a valuation allowance is recorded to reduce the deferred tax assets to the amount expected to be realized. Following the Offering, our operations will be treated as a partnership for federal and state income tax purpose, with each partner being separately taxed on its share of taxable income.

Comprehensive Loss

There are no differences between net income (loss) and comprehensive income (loss) due to the absence of items of other comprehensive income in the periods presented.

Note 3. Transactions with Affiliates

We generate a substantial portion of our revenues from commercial agreements with Noble. Additional detail related to our related party revenue is as follows:

	Three Months Ended March 31,
	2015		2014
($ in thousands)
Midstream Services—Related Party
Crude Oil, Natural Gas and Saltwater Gathering	$	8,788	$	—
Water Delivery		3,063		—
Crude Oil Treating		1,001		513
Total	$	12,852	$	513

We have been historically operated as a part of the consolidated operations of Noble and a substantial portion of our transactions are with Noble and its affiliates. Noble also provides substantial labor and overhead support for us and the accompanying combined financial statements include expense allocations for support functions provided by Noble. These support functions include treasury, tax, accounting, human resources and legal services. In connection with the closing of this offering, we will enter into an agreement to pay a fixed fee for certain overhead support functions. For the three months ended March 31, 2015, our general and administrative charges totaled $0.5 million. Prior to entering into this agreement, allocations of expenses for support functions provided by Noble were based primarily on direct usage when identifiable or capital expenditures during the respective periods. 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 we operated as a stand-alone company for the periods presented. For the three months ended March 31, 2014, we have been allocated and $1.6 million, of general and administrative expenses. Additionally, Noble allocated interest expense to us based on capital expenditures for the periods presented.

F-16

Noble Midstream Partners LP Predecessor

Notes to the Unaudited Combined Financial Statements

Note 4. Property, Plant and Equipment

Property, plant and equipment, at cost, is as follows:

	March 31, 2015			December 31, 2014
($ in thousands)
Crude Oil, Natural Gas and Saltwater Gathering Systems and Facilities	$	115,427		$	109,530
Water Delivery System		40,006			39,952
Crude Oil Treating Facilities		20,232			20,123
Construction-in-Progress		62,080			41,981
Total Property, Plant and Equipment, at Cost		237,745			211,586
Accumulated Depreciation		(17,384	)		(16,073	)
Property, Plant and Equipment, Net	$	220,361		$	195,513

Note 5. Asset Retirement Obligations

AROs consist primarily of estimated costs of dismantlement, removal, site reclamation and similar activities associated with our equipment and facilities. Changes in ARO are as follows:

	Three Months Ended March 31, 2015
($ in thousands)
Asset Retirement Obligations, Beginning Balance	$	2,839
Liabilities Incurred		1,960
Accretion Expense(1)		34
Asset Retirement Obligations, Ending Balance	$	4,833

(1) Accretion expense is included in depreciation, depletion and amortization expense in the combined statements of operations.

Liabilities incurred were related to our centralized gathering facility in Weld County, Colorado.

Note 6. Income Taxes

Income taxes have been prepared on a separate return basis as if the Predecessor was a stand-alone entity. The Predecessor, however, is included in Noble’s U.S. consolidated federal income tax return and also files some U.S. state income tax returns on a combined basis with Noble. All of income before income taxes for the periods presented was earned in the United States.

	Three Months Ended March 31,
	2015		2014
($ in thousands)
Current	$	—	$	—
Deferred		3,409		(2,023	)
Total Income Tax (Benefit) Provision	$	3,409	$	(2,023	)

F-17

Noble Midstream Partners LP Predecessor

Notes to the Unaudited Combined Financial Statements

Our effective tax rate (ETR) for the three months ended March 31, 2015 remained flat as compared with the three months ended March 31, 2014.

A reconciliation of the federal statutory tax rate to the effective tax rate is as follows:

	Three Months Ended March 31,
	2015			2014
(percentages)
Federal Statutory Rate		35.0	%		35.0	%
Effect of
State Taxes, Net of Federal Benefit		2.8	%		2.8	%
Effective Rate		37.8	%		37.8	%

Note 7. Concentration of Credit Risk

Noble accounted for 91% and 40% of our revenue for the three months ended March 31, 2015 and 2014, respectively.

Note 8. Supplemental Cash Flow Information

Noble accrued $9.9 million related to midstream capital expenditures as of March 31, 2015. There were no material accruals for midstream capital expenditures as of March 31, 2014.

Note 9. Segments

Our operations are located in the United States and are organized into four reporting segments: Gathering Systems, Water Delivery, Investments in Midstream Entities, and Partnership and Other. Our reportable segments comprise the structure used by our Chief Operating Decision Maker (“CODM”) to make key operating decisions and assess performance. The accounting policies of the segments are identical to those described in Note 2. Summary of Significant Accounting Policies of these unaudited combined consolidated financial statements.

Partnership expenses include general expenses associated with managing all reportable operating segments. Partnership assets consist primarily of deferred tax assets.

Summarized financial information concerning the Partnership’s reportable segments is shown in the following tables:

	Gathering Systems		Water Delivery		Investments		Partnership and Other			Combined
($ in thousands)
Three Months Ended March 31, 2015
Revenues—Related Party	$	9,789	$	3,063	$	—	$	—		$	12,852
Income from Investments		—		—		1,236		—			1,236
Total Revenues		9,789		3,063		1,236		—			14,088
Income (Loss) before income taxes		6,264		2,730		1,236		(1,217	)		9,013
Total Assets as of March 31, 2015		177,677		42,684		11,590		26,412			258,363

F-18

Noble Midstream Partners LP Predecessor

Notes to the Unaudited Combined Financial Statements

	Gathering Systems			Water Delivery			Investments		Partnership and Other			Combined
($ in thousands)
Three Months Ended March 31, 2014
Revenues—Related Party	$	513		$	—		$	—	$	—		$	513
Income from Investments		—			—			773		—			773
Total Revenues		513			—			773		—			1,286
Income (Loss) before Income Taxes		(2,952	)		(490	)		773		(2,681	)		(5,350	)

Note 10. Unaudited Supplemental Pro Forma Information

Unaudited supplemental pro forma balance sheet and net income (loss) per unit have been presented in accordance with SEC Staff Accounting Bulletin Topic 1.B.3. The supplemental pro forma balance sheet gives effect to the distribution of approximately $         million to Noble to be paid upon completion of the Offering. Accordingly, the Partnership is deemed to have used $         million of net proceeds of the Offering of common units to pay the distribution, which is evidenced by a due to affiliate reflected in the supplemental condensed combined pro forma balance sheet.

The Predecessor had net income of $5.6 million for the three months ended March 31, 2015. Supplemental pro forma net income (loss) per limited partner unit assumes additional common units were issued to give effect to the distribution described above. The supplemental pro forma net income per limited partner unit assumes          common units, which includes the common units that would have been required to be issued in connection with the offering in order to pay the distribution, and          subordinated units were outstanding for the three months ended March 31, 2015. The number of common units deemed to have been sold in the Offering in order to pay the distribution described above is . This number was calculated by dividing the total $         million distribution in excess of earnings for the three months ended March 31, 2015 by the initial public offering price of $         per unit (the mid-point of the price range set forth on the cover page of this prospectus) after deducting underwriting discounts and estimated offering expenses, and would result in net income (loss) of $         per unit.

The Predecessor had net loss of $15.1 million for the year ended December 31, 2014. Supplemental pro forma net income per limited partner unit assumes additional common units were issued to give effect to the distribution described above. The supplemental pro forma net loss per limited partner unit assumes common units, which includes the common units that would have been required to be issued in connection with this offering in order to pay the distribution, and subordinated units were outstanding for the year ended December 31, 2014. The number of common units deemed to have been sold in the Offering in order to pay the distribution described above is         . This number was calculated by dividing the total $         million distribution in excess of earnings for the year ended December 31, 2014 by the initial public offering price of $         per unit (the mid-point of the price range set forth on the cover page of this prospectus) after deducting underwriting discounts and estimated offering expenses and would result in net income loss of $         per unit.

There were no potential common units outstanding to be considered in the pro forma diluted earnings per unit calculation for either period presented.

F-19

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors

Noble Energy, Inc.:

We have audited the accompanying combined balance sheets of Noble Midstream Partners LP Predecessor (the Predecessor) as of December 31, 2014 and 2013, and the related combined statements of operations, changes in net parent investment and cash flows for the years then ended. 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 in accordance with the standards of the Public Company Accounting Oversight Board (United States). 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. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Noble Midstream Partners LP Predecessor as of December 31, 2014 and 2013, and the results of its operations and its cash flows for the years then ended, in conformity with U.S. generally accepted accounting principles.

/s/ KPMG LLP

Houston, Texas

July 24, 2015

F-20

Noble Midstream Partners LP Predecessor

Combined Statements of Operations

(in thousands)

	Year Ended December 31
	2014			2013
Revenues
Midstream Services—Related Party	$	2,086		$	2,169
Income from Investments		3,798			3,024
Total Revenues		5,884			5,193
Costs and Expenses
Direct Operating		8,538			2,760
Depreciation, Depletion and Amortization		11,315			3,092
General and Administrative		6,734			6,124
Total Operating Expenses		26,587			11,976
Operating Loss		(20,703	)		(6,783	)
Other Expense
Interest Expense, Net of Amount Capitalized		3,566			3,263
Total Other Expense		3,566			3,263
Loss Before Income Taxes		(24,269	)		(10,046	)
Income Tax Benefit		(9,178	)		(3,746	)
Net Loss	$	(15,091	)	$	(6,300	)

The accompanying notes are an integral part of these combined financial statements

F-21

Noble Midstream Partners LP Predecessor

Combined Balance Sheets

(in thousands)

	December 31,
	2014			2013
ASSETS
Current Assets
Cash and Cash Equivalents	$	—		$	—
Other Current Assets		—			—
Total Current Assets		—			—
Property, Plant and Equipment
Property, Plant and Equipment		211,586			132,397
Accumulated Depreciation, Depletion and Amortization		(16,073	)		(4,893	)
Total Property, Plant and Equipment, Net		195,513			127,504
Investments		11,077			11,639
Deferred Taxes, Net		9,922			740
Total Assets	$	216,512		$	139,883
LIABILITIES AND NET PARENT INVESTMENT
Current Liabilities
Accounts Payable—Trade	$	—		$	—
Other Current Liabilities		—			—
Total Current Liabilities		—			—
Asset Retirement Obligations		2,839			2,704
Total Liabilities		2,839			2,704
Commitments and Contingencies (Refer to Note 10)
Total Net Equity—Net Parent Investment		213,673			137,179
Total Liabilities and Net Parent Investment	$	216,512		$	139,883

The accompanying notes are an integral part of these combined financial statements

F-22

Noble Midstream Partners LP Predecessor

Combined Statements of Changes in Net Parent Investment

(in thousands)

	Total Net Equity—Net Parent Investment
Balance at January 1, 2013	$	36,498
Net loss		(6,300	)
Transactions with Parent, Net		106,981
Balance at December 31, 2013		137,179
Net loss		(15,091	)
Transactions with Parent, Net		91,585
Balance at December 31, 2014	$	213,673

The accompanying notes are an integral part of these combined financial statements

F-23

Noble Midstream Partners LP Predecessor

Combined Statements of Cash Flows

(in thousands)

	Year Ended December 31,
	2014			2013
Cash Flows from Operating Activities
Net Loss	$	(15,091	)	$	(6,300	)
Adjustments to Reconcile Net Loss to Net Cash Used in Operating Activities
Depreciation, Depletion and Amortization		11,315			3,092
Deferred Income Taxes		(9,182	)		(3,874	)
Stock Based Compensation		424			147
Net Cash Used in Operating Activities		(12,534	)		(6,935	)
Cash Flows From Investing Activities
Additions to Property, Plant and Equipment		(80,466	)		(96,318	)
Distributions from Investments		562			732
Net Cash Used in Investing Activities		(79,904	)		(95,586	)
Cash Flows From Financing Activities
Contributions from Parent, net		92,438			102,521
Net Cash Provided by Financing Activities		92,438			102,521
Increase (Decrease) in Cash and Cash Equivalents		—			—
Cash and Cash Equivalents at Beginning of Period		—			—
Cash and Cash Equivalents at End of Period	$	—		$	—

The accompanying notes are an integral part of these combined financial statements

F-24

Noble Midstream Partners LP Predecessor

Notes to Combined Financial Statements

Note 1. Description of Business and Basis of Presentation

These combined financial statements constitute the contributed midstream assets and liabilities of Noble Energy, Inc. (“Noble”) as the accounting predecessor (the “Predecessor,” “we” or “our”) to a newly formed limited partnership, Noble Midstream Partners LP (the “Partnership”), and have been prepared in connection with the initial public offering (the “Offering”) of common units representing limited partner interests of the Partnership.

The Predecessor’s business includes the contributed assets, liabilities and results of operations of (i) crude oil and natural gas gathering systems located in the DJ Basin in northern Colorado, (ii) crude oil treating facilities in the DJ Basin in northern Colorado, (iii) fresh water storage and delivery and saltwater collection in the DJ Basin in northern Colorado, gathering, cleaning, recycling and disposal systems in the DJ Basin in northern Colorado and (iv) a 3.33% non-controlling member interest in White Cliffs Pipeline, L.L.C. also located in the DJ Basin (the “White Cliffs Interest”) (collectively, the “Contributed Businesses”).

The Contributed Businesses were operated and held by Noble during the periods presented in the accompanying combined financial statements. It is anticipated that controlling interests the Contributed Businesses will be transferred by Noble to the Partnership in connection with the Offering.

The combined financial statements of the Predecessor have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) on the basis of Noble’s historical ownership of the Contributed Businesses.

The accompanying combined statements of operations include expense allocations for certain functions historically performed by Noble but not historically allocated to the Contributed Businesses, including allocations of general corporate services, such as treasury, accounting, human resources and legal services. These allocations were based primarily on direct usage when identifiable or capital expenditures or other relevant allocations during the respective years. We believe the assumptions underlying the accompanying combined financial statements, including the assumptions regarding allocation of expenses from Noble, are reasonable. Nevertheless, the accompanying combined financial statements may not include all of the expenses that would have been incurred and may not reflect our results of operations, financial position and cash flows had we been a stand-alone company during the years presented. Because a direct ownership relationship did not exist among the businesses comprising the Predecessor, the net investment in the Predecessor is shown as Net Parent Investment, in lieu of owner’s equity, in the combined financial statements. No goodwill is included in our combined financial statements as none of the goodwill held by Noble was associated with the historical basis of the Contributed Businesses.

Noble used a centralized approach to the cash management and financing of the Predecessor’s operations prior to January 1, 2015. The Predecessor had no bank accounts during the historical periods presented and, as such, the cash generated by our operations was directly received by Noble, and Noble funded our operating and investing activities as needed. Accordingly, the cash and cash equivalents held by Noble were not allocated to us for any of the years presented. We have reflected cash management and financing activities performed by Noble as a component of net parent investment on our accompanying combined balance sheets, and as contributions from parent, net on our accompanying combined statements of cash flows.

Note 2. Summary of Significant Accounting Policies

Use of Estimates

The preparation of financial statements in conformity with GAAP requires us to make a number of estimates and assumptions relating to the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during

F-25

Noble Midstream Partners LP Predecessor

Notes to Combined Financial Statements

the reporting period. Items subject to estimates and assumptions include the useful lives of property and equipment, obligations for environmental liabilities, allocations of expenses from Noble, deferred tax assets and liabilities, among others. Although management believes these amounts are reasonable, actual results could differ from these estimates.

Cash and Cash Equivalents

Cash and cash equivalents include unrestricted cash on hand and investments with original maturities of three months or less at the time of purchase. As of December 31, 2014 and 2013, the Predecessor’s business did not hold any cash and cash equivalents.

Property, Plant and Equipment

Property, plant and equipment primarily consists of gathering pipelines, facilities and related equipment, which are stated at the lower of historical cost less accumulated depreciation, or fair value, if impaired. We capitalize construction-related direct labor, material costs and the interest related to construction. Maintenance and repair costs are expensed as incurred.

Prior to January 1, 2015, certain assets were accounted for under the successful efforts method of accounting within Noble’s accounting policies. Under this method, costs to acquire mineral interests in crude oil and natural gas properties, drill and equip exploratory wells that find proved reserves, and drill and equip development wells are capitalized. Capitalized costs of producing crude oil and natural gas properties, along with support equipment and facilities, are amortized to expense by the unit-of-production method based on proved crude oil, natural gas and NGL reserves on a field-by-field basis, as estimated by Noble’s qualified petroleum engineers. Noble’s policy is to use quarter-end reserves and add back current period production to compute quarterly depreciation, depletion and amortization expense. Costs of certain gathering facilities serving a number of properties are depreciated using the straight-line method over the useful lives of the assets ranging from three to 30 years. Upon sale or retirement of depreciable or depletable property, the cost and related accumulated depreciation, depletion and amortization are eliminated from the accounts and the resulting gain or loss is recognized.

Although Noble has historically operated the midstream assets in support of the U.S. onshore upstream business as a cost center within the United States reportable segment, beginning in January 2015, Noble elected to begin operating the midstream business as if it were a stand-alone business. However, the midstream business will continue to be consolidated by Noble and reported within Noble’s consolidated financial statements. Due to the change in the intended use of these assets, Noble changed the method of depreciation from units-of-production to the preferable straight-line method for future accounting periods. This change is a change in accounting estimate that is effected by a change in accounting principle. When the two are inseparable, the change is accounted for as a change in accounting estimate. Depreciation will be calculated on a straight-line basis prospectively from the first quarter of 2015, the period of change, and in prospective periods. Following this adjustment, our assets will have useful lives ranging from 24 to 30 years. For assets that were converted from the unit-of-production method, their respective asset lives will be 30 years from the date originally placed into service. If Noble had made this change in January of 2013, depreciation expense would have been $4.7 million and $1.2 million for the years ended December 31, 2014 and 2013, respectively.

Property and equipment included assets under construction of $42.0 million and $36.1 million at December 31, 2014 and 2013, respectively.

F-26

Noble Midstream Partners LP Predecessor

Notes to Combined Financial Statements

Capitalization of Interest

We capitalize interest costs associated with the development and construction of significant assets or projects to bring them to a condition and location necessary for their intended use. Interest is capitalized using an interest rate equivalent to the weighted average rate Noble pays on long-term debt. Capitalized interest is included in property, plant and equipment and is depreciated over the life of the asset. Capitalized interest totaled $1.6 million and $3.1 million, for the years ended December 31, 2014 and 2013, respectively.

Investments

We use the cost method of accounting for investments in entities that we do not control, or exert significant influence over. We carry the investments at cost on our combined balance sheet and recognize dividends on our combined statement of operations when received. Dividends received in excess of earnings are recorded as a return of capital on the combined balance sheet. We account for our investment in the White Cliffs Interest under the cost method of accounting for investments because we have virtually no influence over partnership operations and financial policies.

Asset Retirement Obligations

Asset retirement obligations (“AROs”) consist of estimated costs of dismantlement, removal, site reclamation and similar activities associated with our equipment and facilities. We recognize the fair value of a liability for an ARO in the period in which it is incurred and when we have an existing legal obligation associated with the retirement of our properties that can reasonably be estimated. The associated asset retirement cost is capitalized as part of the carrying cost of the asset. The asset retirement cost is determined at current costs and is inflated into future dollars using an inflation rate that is based on the consumer price index. The future projected cash flows are then discounted to their present value using a credit-adjusted risk-free rate. After initial recording, the liability is increased for the passage of time, with the increase being reflected as accretion expense and included in our depreciation, depletion and amortization expense in the combined statement of operations. Subsequent adjustments in the cost estimate are reflected in the liability and the amounts continue to be amortized over the useful life of the related long-lived asset.

There were no ARO additions during the year ended December 31, 2014. The non-cash ARO addition was $2.7 million for the year ended December 31, 2013.

Net Parent Investment

In the accompanying combined balance sheets, net parent investment represents Noble’s historical investment in us, our accumulated net results, and the net effect of transactions with, and allocations from, Noble.

Revenue Recognition

We recognize revenues when persuasive evidence of an arrangement exists, delivery has occurred or services have been rendered, price is fixed or determinable and collectability is reasonably assured. Beginning in January 2015, we earn substantially all of our revenues from our commercial agreements we have entered into with Noble.

We recognized related party revenues of $2.1 million and $2.2 million from Noble during the years ended December 31, 2014 and 2013, respectively.

F-27

Noble Midstream Partners LP Predecessor

Notes to Combined Financial Statements

Income Taxes

We are not a separate taxable entity for U.S. Federal and states income tax purposes, and our results are included in the consolidated income tax returns of Noble. The provision for income taxes and income tax assets and liabilities were determined as if we were a stand-alone taxpayer for all periods presented. Deferred income taxes are determined using the liability method and reflect temporary differences between the financial statement carrying amount and income tax basis of assets and liabilities recorded using the currently enacted statutory income tax rate. Regular assessments are made of the likelihood of those deferred tax assets being realized. If it is more likely than not that some or all of the deferred tax assets will not be realized, a valuation allowance is recorded to reduce the deferred tax assets to the amount expected to be realized. Following the Offering, our operations will be treated as a partnership for federal and state income tax purposes, with each partner being separately taxed on its share of taxable income.

Stock-Based Compensation

The Predecessor’s financial statements reflect various stock-based compensation awards granted by Noble to certain employees of the midstream business. Stock options and other stock-based compensation awards granted to employees and directors are recorded at grant-date fair value. Expense is recognized on a straight-line basis over the employee’s requisite service period (generally the vesting period of the award) in the combined statements of operations. For purposes of these combined financial statements, the Predecessor recognized the relevant amounts as expense in each period, with the offset included in net parent investment. These expenses were based primarily on direct usage during the respective years.

Comprehensive Loss

There are no differences between net loss and comprehensive loss due to the absence of items of other comprehensive income in the periods presented.

Note 3. Transactions with Affiliates

We have been historically operated as a part of the consolidated operations of Noble and a substantial portion of our transactions are with Noble and its affiliates. Employees of Noble provided services to us, and are included within our direct operating cost. Noble also provides substantial labor and overhead support for us and the accompanying combined financial statements include expense allocations for support functions provided by Noble. These support functions include general and administrative services, such as information technology, treasury, tax, accounting, human resources and legal services. These expense allocations are based primarily on direct usage when identifiable or capital expenditures or other relevant allocations during the respective periods. 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 we operated as a stand-alone company for the periods presented. For the years ended December 31, 2014 and 2013, we have been allocated $6.7 million and $6.1 million, respectively, of general and administrative expenses. Additionally, Noble allocated interest expense to us based on capital expenditures for the periods presented. See also Note 2. Summary of Significant Accounting Policies—Net Parent Investment and Revenue Recognition to these audited combined financial statements.

F-28

Noble Midstream Partners LP Predecessor

Notes to Combined Financial Statements

Note 4. Property, Plant and Equipment

Property, plant and equipment, at cost, is as follows:

	December 31,
	2014			2013
($ in thousands)
Crude Oil, Natural Gas and Saltwater Gathering Systems and Facilities	$	109,530		$	74,785
Crude Oil Treating Facilities		20,123			6,681
Water Delivery System		39,952			14,808
Construction-in-Progress		41,981			36,123
Total Property, Plant and Equipment, at Cost		211,586			132,397
Accumulated Depreciation		(16,073	)		(4,893	)
Property, Plant and Equipment, Net	$	195,513		$	127,504

Note 5. Asset Retirement Obligations

AROs consist primarily of estimated costs of dismantlement, removal, site reclamation and similar activities associated with our equipment and facilities. Changes in AROs are as follows:

	December 31,
	2014		2013
($ in thousands)
Asset Retirement Obligations, Beginning Balance	$	2,704	$	—
Liabilities Incurred		—		2,704
Accretion Expense(1)		135		—
Asset Retirement Obligations, Ending Balance	$	2,839	$	2,704

(1) Accretion expense is included in depreciation, depletion and amortization expense in the combined statements of operations.

For the Year ended December 31, 2014

No additional liabilities were incurred.

For the Year ended December 31, 2013

Liabilities incurred were related to our centralized gathering facility and crude oil treating facilities in Weld County, Colorado.

Note 6. Stock-Based Compensation

Certain Noble employees supporting our operations were granted stock-based compensation awards under Noble stock option and restricted stock plans. Expenses associated with these Noble stock-based compensation awards were included in the Predecessor’s combined statements of operations during the respective years. In 2014, we recognized $424,000 of expense related to Noble stock compensation awards, of which approximately $376,000 is reported in our direct operating expenses and $48,000 is reported in general and administrative expense. In 2013, we recognized $147,000 of expense related to Noble stock compensation awards, of which approximately $130,000 is reported in our operating expenses and $17,000 is reported in general and administrative expense.

F-29

Noble Midstream Partners LP Predecessor

Notes to Combined Financial Statements

Noble’s stock-based compensation plans may grant stock options and stock appreciation rights and award restricted stock and cash awards to our officers or other employees and those of our subsidiaries. Stock options are issued with an exercise price equal to the fair market value of Noble’s common stock on the date of grant, and are subject to such other terms and conditions as may be determined by the Compensation, Benefits, and Stock Option Committee (the “Committee”) of Noble’s Board of Directors. Unless granted by the Committee for a shorter term, the options expire 10 years from the grant date. Option grants generally vest ratably over a three-year period.

Restricted stock awards with a time-vested restriction vest over a three year period (20% after year one, an additional 30% after year two and the remaining 50% after year three) or over a two year period (40% after year one and the remaining 60% after year two). Restricted stock awards with a performance-vested restriction cliff vest after a three year period if Noble achieves certain levels of total shareholder return relative to a pre-determined industry peer group.

Stock Option Grants

The fair value of each stock option granted was estimated on the date of grant using a Black-Scholes-Merton option valuation model that used the assumptions described below:

• Expected term. The expected term represents the period of time that options granted are expected to be outstanding, which is the grant date to the date of expected exercise or other expected settlement for options granted. The hypothetical midpoint scenario considers Noble’s actual exercise and post-vesting cancellation history and expectations for future periods, which assumes that all vested, outstanding options are settled halfway between the current date and their expiration date.

• Expected volatility. The expected volatility represents the extent to which Noble’s stock price is expected to fluctuate between the grant date and the expected term of the award. Historical volatility of Noble’s common stock relates to a period equal to the expected term of the option prior to the date of grant. Historical volatility produces an estimate that is representative of Noble’s expectations about the future volatility of Noble’s common stock over the expected term.

• Risk-free rate. The risk-free rate is the implied yield available on US Treasury securities with a remaining term equal to the expected term of the option. The risk-free rate is based on a weighting of five and seven year US Treasury securities as of the date of grant.

• Dividend yield. The dividend yield represents the value of Noble’s stock’s annualized dividend as compared to Noble’s stock’s average price for the three-year period ended prior to the date of grant. It is calculated by dividing one full year of Noble’s expected dividends by Noble’s average stock price over the three-year period ended prior to the date of grant.

The assumptions used in valuing Noble’s stock options granted were as follows:

	Year Ended December 31,
	2014			2013
(weighted averages)
Expected Term (in Years)		5.9			5.7
Expected Volatility		35.1	%		36.4	%
Risk-Free Rate		1.8	%		1.1	%
Expected Dividend Yield		1.1	%		1.2	%
Weighted Average Grant-Date Fair Value	$	20.31		$	17.08

F-30

Noble Midstream Partners LP Predecessor

Notes to Combined Financial Statements

Restricted Stock Awards

Awards of time-vested restricted stock (shares subject to service conditions) are valued at the price of Noble’s common stock at the date of award. The fair values of market based restricted stock awards are estimated on the grant date of award using a Monte Carlo valuation model that uses the assumptions in the following table. The Monte Carlo model is based on random projections of stock price paths and must be repeated numerous times to achieve a probabilistic assessment. Expected volatility represents the extent to which Noble’s stock price is expected to fluctuate between now and the award’s anticipated term. The calculation uses the historical volatility of Noble’s common stock for the three-year period ended prior to the date of award. The risk-free rate is based on a three-year period for U.S. Treasury securities as of the year ended prior to the date of award.

The assumptions used in valuing Noble’s market based restricted stock awards granted were as follows:

	Year Ended December 31,
	2014			2013
Number of Simulations		500,000			500,000
Expected Volatility		30	%		30	%
Risk-Free Rate		0.7	%		0.4	%

The weighted average award-date fair value of Noble’s restricted stock awarded was $41.22 per share in 2014 and $38.07 per share in 2013.

Note 7. Income Taxes

Income taxes have been prepared on a separate return basis as if the Predecessor was a stand-alone entity. The Predecessor, however, is included in the Noble Energy, Inc. U.S. consolidated federal income tax return and U.S. state income tax returns on a combined basis with Noble, as required. All of income before income taxes for the periods presented was earned in the United States.

The income tax benefit consists of the following:

	Year Ended December 31,
	2014			2013
($ in thousands)
Current Taxes
Federal	$	—		$	—
State		4			128
Total Current		4			128
Deferred Taxes
Federal		(8,494	)		(3,516	)
State		(688	)		(358	)
Total Deferred		(9,182	)		(3,874	)
Total Income Tax Provision		(9,178	)		(3,746	)

F-31

Noble Midstream Partners LP Predecessor

Notes to Combined Financial Statements

A reconciliation of the federal statutory tax rate to the effective tax rate is as follows:

	Year Ended December 31,
	2014			2013
(percentages)
Federal Statutory Rate		35.0	%		35.0	%
Effect of
State Taxes, Net of Federal Benefit		2.8	%		2.3	%
Effective Rate		37.8	%		37.3	%

The components of deferred tax assets and liabilities are as follows:

	Year Ended December 31,
	2014			2013
($ in thousands)
Deferred Tax Assets
Loss Carryforwards	$	18,839		$	5,469
Total Deferred Tax Assets		18,839			5,469
Deferred Tax Liabilities
Property, Plant and Equipment, and Investment in White Cliffs Pipeline, L.L.C.		(8,917	)		(4,729	)
Total Deferred Tax Liability		(8,917	)		(4,729	)
Net Deferred Tax Asset	$	9,922		$	740

At December 31, 2014, we had net operating losses (NOL) of $49.4 million that, if unused, will begin to expire in 2034. The realization of the deferred tax asset related to the NOL is dependent upon generating sufficient taxable income in the applicable jurisdictions. We believe future revenue will generate sufficient taxable income to utilize the NOL and a valuation allowance will not be required.

Note 8. Concentration of Credit Risk

Prior to January 1, 2015, the Midstream Business operated as part of the integrated operations of Noble, and did not have credit risk.

Note 9. Supplemental Cash Flow Information

Noble accrued $5.0 million and $6.3 million related to midstream capital expenditures as of December 31, 2014 and 2013, respectively. During the years presented, the Contributed Business operated as part of the integrated operations of Noble, and Noble funded our operating and investing activities as needed.

F-32

Noble Midstream Partners LP Predecessor

Notes to Combined Financial Statements

Note 10. Commitments and Contingencies

Legal Proceedings

For the periods presented, we were part of Noble’s integrated business. In the ordinary course of business, Noble is from time to time party to various judicial and administrative proceedings. Noble regularly assesses the need for accounting recognition or disclosure of these contingencies. In the case of a known contingency, Noble accrues a liability when the loss is probable and the amount is reasonably estimable. If a range of amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum of the range is accrued. As of December 31, 2014 and 2013, Noble did not have accrued liabilities for any legal contingencies related to us. Based on currently available information, we believe it is remote that the outcome of known matters would have a material adverse impact on our combined financial condition, results of operations or cash flows.

Note 11. Segments

Our operations are located in the United States and are organized into four reporting segments: Gathering Systems, Water Delivery, Investments in Midstream Entities, and Partnership and Other. Our reportable segments comprise the structure used by our Chief Operating Decision Maker (“CODM”) to make key operating decisions and assess performance. The accounting policies of the segments are identical to those described in Note 2. Summary of Significant Accounting Policies.

Partnership expenses include general expenses associated with managing all reportable operating segments. Partnership assets consist primarily of deferred tax assets.

Summarized financial information concerning the Partnership’s reportable segments is shown in the following tables:

	Gathering Systems			Water Delivery			Investments		Partnership and Other			Combined
($ in thousands)
Year Ended December 31, 2014
Revenues—Related Party	$	2,086		$	—		$	—	$	—		$	2,086
Income from Investments		—			—			3,798		—			3,798
Total Revenues		2,086			—			3,798		—			5,884
Income (Loss) before Income Taxes		(13,381	)		(2,303	)		3,798		(12,383	)		(24,269	)
Additions to Long-Lived Assets		64,947			14,242			—		—			79,189
Total Assets at End of Year		156,302			39,211			11,077		9,922			216,512

	Gathering Systems			Water Delivery			Investments		Partnership and Other			Combined
($ in thousands)
Year Ended December 31, 2013
Revenues—Related Party	$	2,169		$	—		$	—	$	—		$	2,169
Income from Investments		—			—			3,024		—			3,024
Total Revenues		2,169			—			3,024		—			5,193
Income (Loss) before Income Taxes		(1,712	)		(925	)		3,024		(10,433	)		(10,046	)
Additions to Long-Lived Assets		87,175			15,590			—		—			102,765
Total Assets at End of Year		100,237			27,267			11,639		740			139,883

F-33

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Partners of Noble Midstream Partners LP

We have audited the accompanying balance sheet of Noble Midstream Partners LP (the Partnership) as of July 17, 2015. This balance sheet is the responsibility of the Partnership’s management. Our responsibility is to express an opinion on this balance sheet based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the balance sheet is free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall balance sheet presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Noble Midstream Partners LP as of July 17, 2015 in conformity with U.S. generally accepted accounting principles.

/s/ KPMG LLP

Houston, Texas

July 24, 2015

F-34

Noble Midstream Partners LP

Balance Sheet

	July 17, 2015
Assets
Cash	$	1,000
Total Assets	$	1,000
Partners’ Capital
Limited Partner		980
General Partner		20
Total Partners’ Capital	$	1,000

The accompanying notes are an integral part of these financial statements

F-35

Noble Midstream Partners LP

Notes to Balance Sheet

Note 1. Description of Business and Basis of Presentation

Noble Midstream Partners LP (“we” or the “Partnership”) is a Delaware limited partnership, which was formed on December 23, 2014 but has not yet commenced operations. Noble Midstream Partners GP LLC (the “General Partner”) is a limited liability company formed on December 23, 2014 to become the General Partner of the Partnership.

On December 23, 2014, in connection with the formation of the Partnership, Noble Midstream Partners LP issued to (i) Noble Midstream Partners GP LLC a 1% General Partner interest in the Partnership for $20 and (ii) to Noble Midstream Services, LLC, a 99% limited partner interest in the Partnership for $980.

F-36

APPENDIX A

FORM OF

FIRST AMENDED AND RESTATED

AGREEMENT OF LIMITED PARTNERSHIP

OF

NOBLE MIDSTREAM PARTNERS LP

A Delaware Limited Partnership

Dated as of

                    , 2015

A-1

APPENDIX B Glossary of Terms

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

Bbl/d: Bbl per day.

BBtu: One billion British thermal units.

BBtu/d: BBtu per day.

Bcfe: One billion cubic feet of natural gas equivalent with one barrel of crude oil or NGLs converted to six thousand cubic feet of natural gas.

Bcfe/d: Bcfe per day.

Boe: Barrels of crude oil equivalent.

Boe/d: Boe per day.

Bpm: Barrels per month.

Brent: Brent Crude, a crude oil pricing benchmark.

Btu: British thermal units.

DJ Basin: Denver-Julesburg Basin, a geologic structural basin centered in eastern Colorado.

DOT: The U.S. Department of Transportation.

EIA: The U.S. Energy Information Administration.

EPA: The U.S. Environmental Protection Agency.

FERC: The U.S. Federal Energy Regulatory Commission.

field: The general area encompassed by one or more crude 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).

hydrocarbon: An organic compound containing only carbon and hydrogen.

IRS: The Internal Revenue Service.

MBbl: One thousand barrels.

MBbl/d: One thousand barrels per day.

MBoe: Thousand barrels of crude oil equivalent.

MBoe/d: MBoe per day.

Mcf: One thousand cubic feet of natural gas.

Mcf/d: One thousand cubic feet per day.

B-1

MMBoe: One million barrels of crude oil equivalent.

MMBtu: One million British thermal units.

MMBbl: One million barrels.

MMBbl/d: One million barrels per day.

MMcf: One million cubic feet of natural gas.

MMcfe: One million cubic feet equivalent, determined using a ratio of six Mcf of natural gas to one barrel of crude oil or NGLs.

MMcf/d: One million cubic feet per day.

MMcfe/d: One million cubic feet equivalent per day.

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.

NYMEX: New York Mercantile Exchange.

OECD: Organisation for Economic Co-operation and Development

SEC: The U.S. Securities and Exchange Commission.

PHMSA: Pipeline and Hazardous Materials Safety Administration.

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

WTI: West Texas Intermediate, a crude oil pricing benchmark.

B-2

Noble Midstream Partners LP

Common Units

Representing Limited Partner Interests

Prospectus

                    , 2015

Joint Book-Running Managers

Barclays

Baird

Through and including                     , 2015 (the 25th day after the date of this prospectus), federal securities laws may require all dealers that effect transactions in these securities, whether or not participating in this offering, to deliver a prospectus. This requirement is in addition to a dealer’s obligation to deliver a prospectus when acting as an underwriter and with respect to an unsold allotment or subscription.

Part II

Information Not Required in Prospectus

Item 13. Other Expenses of Issuance and Distribution

Set forth below are the expenses (other than underwriting discounts and commissions and the structuring fee) 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.

SEC registration fee	$	*
FINRA filing fee		*
NYSE listing fee		*
Printing and engraving expenses		*
Fees and expenses of legal counsel		*
Accounting fees and expenses		*
Transfer agent and registrar fees		*
Miscellaneous		*
Total	$	*

* To be provided by amendment.

Item 14. Indemnification of Directors and Officers

The section of the prospectus entitled “Our Partnership Agreement—Indemnification” discloses that we will generally indemnify officers, directors and affiliates of the 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. Reference is also made to the underwriting agreement to be filed as an exhibit to this registration statement in which Noble Midstream Partners LP and certain of its affiliates will agree to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act, and to contribute to payments that may be required to be made in respect of these liabilities. Subject to any terms, conditions or restrictions set forth in the partnership agreement, Section 17-108 of the Delaware Act empowers a Delaware limited partnership to indemnify and hold harmless any partner or other persons from and against all claims and demands whatsoever.

Item 15. Recent Sales of Unregistered Securities

On December 23, 2014, in connection with the formation of the partnership, Noble Midstream Partners LP issued to Noble Midstream GP LLC a 1% general partner interest in the partnership for $20.00 and a 99% limited partner interest in the partnership for $980.00 in an offering exempt from registration under Section 4(2) of the Securities Act. There have been no other sales of unregistered securities within the past three years.

II-1

Item 16. Exhibits

The following documents are filed as exhibits to this registration statement:

Exhibit number	Description
1.1*	Form of Underwriting Agreement (including form of Lock-Up Agreement)
3.1*	Certificate of Limited Partnership of Noble Midstream Partners LP
3.2*	Amendment to the Certificate of Limited Partnership of Noble Midstream Partners LP
3.3*	Form of First Amended and Restated Agreement of Limited Partnership of Noble Midstream Partners LP (included as Appendix A to the Prospectus)
3.4*	Certificate of Formation of Noble Midstream GP LLC
3.5*	First Amended and Restated Limited Liability Company Agreement of Noble Midstream GP LLC
5.1*	Opinion of Andrews Kurth LLP as to the legality of the securities being registered
8.1*	Opinion of Andrews Kurth LLP relating to tax matters
10.1*	Form of Contribution, Conveyance and Assumption Agreement
10.2*#	Form of Noble Midstream Partners LP 2015 Long-Term Incentive Plan
10.3*	Form of Omnibus Agreement
10.4*	Form of Operational Services Agreement
10.5*	Form of Secondment Agreement
10.6*	Form of Credit Agreement
10.7*	Amended and Restated Natural Gas Gathering Agreement, dated effective as of                , 2015 by and between Noble Energy, Inc. and Noble Midstream Services, LLC
10.8*	Second Amended and Restated Crude Oil Treating Agreement, dated effective as of                , 2015 by and between Noble Energy, Inc. and Noble Midstream Services, LLC
10.9*	Amended and Restated Saltwater Services Agreement, dated effective as of                , 2015 by and between Noble Energy, Inc. and Noble Midstream Services, LLC
10.10*	Amended and Restated Fresh Water Services Agreement, dated effective as of                , 2015 by and between Noble Energy, Inc. and Noble Midstream Services, LLC
10.11*	Amended and Restated Crude Oil Gathering Agreement, dated effective as of                , 2015 by and between Noble Energy, Inc. and Noble Midstream Services, LLC
10.12*	Form of Agreement of Limited Partnership of NBLX DevCo I LP
10.13*	Form of Agreement of Limited Partnership of NBLX DevCo II LP
10.14*	Form of Agreement of Limited Partnership of NBLX DevCo III LP
10.15*	Form of Agreement of Limited Partnership of NBLX DevCo IV LP
10.16*	Form of Agreement of Limited Partnership of NBLX DevCo V LP
21.1*	List of Subsidiaries of Noble Midstream Partners LP
23.1*	Consent of KPMG LLP
23.2*	Consent of Andrews Kurth LLP (contained in Exhibit 5.1)
23.3*	Consent of Andrews Kurth LLP (contained in Exhibit 8.1)
24.1*	Powers of Attorney (contained on the signature page to this Registration Statement)

* To be filed by amendment.

# Compensatory plan, contract or arrangement.

II-2

Item 17. Undertakings

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,

(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.

(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.

(3) That, for the purpose of determining liability under the Securities Act of 1933 to any purchaser, 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.

(4) That, for the purpose of determining liability of the registrant under the Securities Act of 1933 to any purchaser in the initial distribution of the securities, the undersigned registrant undertakes that 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:

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

(b) 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

II-3

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;

(c) 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;

(d) 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

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

The undersigned registrant undertakes to send to each common unitholder, at least on an annual basis, a detailed statement of any transactions with Noble Midstream GP LLC, our general partner, or its affiliates and of fees, commissions, compensation and other benefits paid, or accrued to Noble Midstream GP LLC or its 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.

II-4

SIGNATURES

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                     , 2015.

NOBLE MIDSTREAM PARTNERS LP
By:	Noble Midstream GP LLC,
	its general partner

By:
	Christian S. Kendall
	Chief Executive Officer

POWER OF ATTORNEY

Each person whose signature appears below appoints             and             , and each of them, any of whom may act without the joinder of the other, 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 attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done in connection therewith, as fully to all intents and purposes as he might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or any of them, or their or his substitute and substitutes, 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 indicated on                     , 2015.

Christian S. Kendall	Chief Executive Officer and Director (Principal Executive, Financial and Accounting Officer)
Kenneth M. Fisher	Chairman of the Board of Directors
Charles J. Rimer	Director
Gary W. Willingham	Director

II-5

Exhibit Index

Exhibit number		Description
	1.1*	Form of Underwriting Agreement (including form of Lock-Up Agreement)
	3.1*	Certificate of Limited Partnership of Noble Midstream Partners LP
	3.2*	Amendment to the Certificate of Limited Partnership of Noble Midstream Partners LP
	3.3*	Form of First Amended and Restated Agreement of Limited Partnership of Noble Midstream Partners LP (included as Appendix A to the Prospectus)
	3.4*	Certificate of Formation of Noble Midstream GP LLC
	3.5*	First Amended and Restated Limited Liability Company Agreement of Noble Midstream GP LLC
	5.1*	Opinion of Andrews Kurth LLP as to the legality of the securities being registered
	8.1*	Opinion of Andrews Kurth LLP relating to tax matters
	10.1*	Form of Contribution, Conveyance and Assumption Agreement
	10.2*#	Form of Noble Midstream Partners LP 2015 Long-Term Incentive Plan
	10.3*	Form of Omnibus Agreement
	10.4*	Form of Operational Services Agreement
	10.5*	Form of Secondment Agreement
	10.6*	Form of Credit Agreement
	10.7*	Amended and Restated Natural Gas Gathering Agreement, dated effective as of                , 2015 by and between Noble Energy, Inc. and Noble Midstream Services, LLC
	10.8*	Second Amended and Restated Crude Oil Treating Agreement, dated effective as of                 , 2015 by and between Noble Energy, Inc. and Noble Midstream Services, LLC
	10.9*	Amended and Restated Saltwater Services Agreement, dated effective as of                , 2015 by and between Noble Energy, Inc. and Noble Midstream Services, LLC
	10.10*	Amended and Restated Fresh Water Services Agreement, dated effective as of                , 2015 by and between Noble Energy, Inc. and Noble Midstream Services, LLC
	10.11*	Amended and Restated Crude Oil Gathering Agreement, dated effective as of                , 2015 by and between Noble Energy, Inc. and Noble Midstream Services, LLC
	10.12*	Form of Agreement of Limited Partnership of NBLX DevCo I LP
	10.13*	Form of Agreement of Limited Partnership of NBLX DevCo II LP
	10.14*	Form of Agreement of Limited Partnership of NBLX DevCo III LP
	10.15*	Form of Agreement of Limited Partnership of NBLX DevCo IV LP
	10.16*	Form of Agreement of Limited Partnership of NBLX DevCo V LP
	21.1*	List of Subsidiaries of Noble Midstream Partners LP
	23.1*	Consent of KPMG LLP
	23.2*	Consent of Andrews Kurth LLP (contained in Exhibit 5.1)
	23.3*	Consent of Andrews Kurth LLP (contained in Exhibit 8.1)
	24.1*	Powers of Attorney (contained on the signature page to this Registration Statement)

* To be filed by amendment.

# Compensatory plan, contract or arrangement.

II-6