UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C.  20549

FORM 10-K

ý ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2018

or

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from          to          

Commission file number: 001-37640

NOBLE MIDSTREAM PARTNERS LP

(Exact name of registrant as specified in its charter)

Delaware	47-3011449
(State or other jurisdiction of incorporation or organization)	(I.R.S. employer identification number)
1001 Noble Energy Way
Houston, Texas	77070
(Address of principal executive offices)	(Zip Code)
(281) 872-3100 (Registrant’s telephone number, including area code) Securities registered pursuant to section 12(b) of the Act:
Title of each class	Name of each exchange on which registered
Common Units, Representing Limited Partner Interests	New York Stock Exchange

Securities registered pursuant to section 12(g) of the Act: None 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. ý Yes o No 

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. o Yes ý No 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. ý Yes o No 

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). ý Yes o No 

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ý 

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

Large accelerated filer ý Accelerated filer o Non-accelerated filer o Smaller reporting company o Emerging growth company o

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o

 Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).o Yes ý No

The aggregate market value of the registrant's Common Units held by non-affiliates of the registrant as of June 30, 2018, the last business day of the registrant's most recently completed second fiscal quarter was approximately $1.1 billion.

The registrant had 23,885,880 Common Units and 15,902,584 Subordinated Units outstanding as of February 15, 2019.

DOCUMENTS INCORPORATED BY REFERENCE: None

Table of Contents

PART I
Items 1. and 2.	Business and Properties	3
Item 1A.	Risk Factors	23
Item 1B.	Unresolved Staff Comments	48
Item 3.	Legal Proceedings	48
Item 4.	Mine Safety Disclosures	48
PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	49
Item 6.	Selected Financial Data	52
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	53
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	71
Item 8.	Financial Statements and Supplementary Data	72
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	101
Item 9A.	Controls and Procedures	101
Item 9B.	Other Information	101
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	102
Item 11.	Executive Compensation	107
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	120
Item 13.	Certain Relationships and Related Transactions, and Director Independence	122
Item 14.	Principal Accounting Fees and Services	126
PART IV
Item 15.	Exhibits, Financial Statement Schedules	128
Item 16.	Form 10-K Summary	136

Disclosure Regarding Forward-Looking Statements

This Annual Report on Form 10-K (Form 10-K or Annual Report) contains forward-looking statements within the meaning of the federal securities laws. Forward-looking statements are predictive in nature, depend upon or refer to future events or conditions or include words such as “anticipate,” “estimate,” “believe,” “budget,” “continue,” “could,” “intend,” “may,” “plan,” “potential,” “predict,” “seek,” “should,” “will,” “would,” “expect,” “objective,” “projection,” “forecast,” “goal,” “guidance,” “outlook,” “effort,” “target,” “on schedule”, “strategy” and other similar expressions that are predictions of or indicate future events and trends and that do not relate to historical matters. Our forward-looking statements may 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.

Forward-looking statements are not guarantees of future performance and are based on certain assumptions and bases, and subject to certain risks, uncertainties and other factors, many of which are beyond the Partnership’s control and difficult to predict, and not all of which can be disclosed in advance. 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. While you should not consider the following list to be a complete statement of all potential risks and uncertainties, some of the factors that could cause our actual results to differ materially from the results contemplated by such forward-looking statements include:

• the ability of our customers to meet their drilling and development plans;

• 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, natural gas and produced water gathering and processing services, crude oil treating and fresh water 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 our customers 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;

• interruption of the Partnership’s operations due to social, civil or political events or unrest;

• terrorist attacks or cyber threats;

• any future acquisitions or dispositions of assets or the delay or failure of any such transaction to close; and

• certain factors discussed elsewhere in this Form 10-K. 

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 and unknown risks, uncertainties and other factors, including the factors described under Item 1A. Risk Factors, below, 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. You should consider carefully the statements under Item 1A. Risk Factors and other sections of this report, which describe factors that could cause our actual results to differ from those set forth in the forward-looking statements.

Unless otherwise stated or the context otherwise indicates, references in this report to “Predecessor,” “we,” “our,” “us” or like terms, when referring to periods prior to September 20, 2016, refer to Noble’s Contributed Businesses (as defined herein), our Predecessor for accounting purposes. All references to “Noble Midstream Partners,” “NBLX,” “the Partnership,” “us,” “our,” “we” or similar expressions, when referring to periods after September 20, 2016, refer to Noble Midstream Partners LP, including its consolidated subsidiaries. References to “Noble” may refer to Noble Energy Inc. and/or its consolidated subsidiaries, depending on the context. Our future results of operations may not be comparable to our Predecessor’s historical results of operations. For a summary of commonly used industry terms and abbreviations used in this report, see the Glossary.

PART I

Items 1. and 2. Business and Properties

Overview

We are a growth-oriented Delaware master limited partnership formed in December 2014 by our Parent, 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 through long-term, fixed-fee contracts, as well as purchase crude oil from producers and sell crude oil to customers at various delivery points on our gathering systems. Our business activities are conducted through three reportable segments: Gathering Systems (primarily includes crude oil, natural gas and produced water gathering and crude oil sales), Fresh Water Delivery, and Investments and Other. Our current areas of focus are in the Denver-Julesburg Basin in Colorado (DJ Basin) and the Southern Delaware Basin position of the Permian Basin (Delaware Basin) in Texas. The locations of our current areas of focus are shown in the map below:

We are Noble’s primary vehicle for midstream operations in the onshore United States. We have acreage dedications spanning approximately 460,000 acres in the DJ Basin (with over 230,000 dedicated acres from Noble and the remaining dedicated acres from various third parties) and approximately 121,000 acres in the Delaware Basin (with 108,000 dedicated acres from Noble and the remaining from various third parties).

In addition to our existing operations and acreage dedications, Noble has granted us rights of first refusal (ROFRs) on a combination of midstream assets retained, developed or acquired by Noble and services not already dedicated to us in the DJ Basin, Eagle Ford Shale and Delaware Basin, which includes approximately 79,000 additional acres in the DJ Basin, approximately 35,000 acres in the Eagle Ford Shale and approximately 108,000 acres in the Delaware Basin. Noble has also granted us a ROFR on certain onshore United States acreage that may be acquired in the future.

We believe we are well positioned to (i) develop our infrastructure in a manner and on a timeline that will allow us to handle increasing volumes that we anticipate will result from our customers’ drilling programs on our dedicated properties and (ii) attract new customers in the DJ Basin, Delaware Basin and future areas of operation as we continue to expand our existing, build out new, or acquire, midstream systems and facilities.

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2018 Developments

Black Diamond Acquisition

On January 31, 2018, Black Diamond Gathering LLC (Black Diamond), an entity formed by Black Diamond Gathering Holdings LLC (the Noble Member), a wholly-owned subsidiary of the Partnership, and Greenfield Midstream, LLC (the Greenfield Member), completed the acquisition of all of the issued and outstanding limited liability company interests (the Black Diamond Acquisition) in Saddle Butte Rockies Midstream, LLC and certain affiliates (collectively, Saddle Butte) from Saddle Butte Pipeline II, LLC (Seller).

Black Diamond completed the Black Diamond Acquisition for approximately $638.5 million in cash. Noble Member and Greenfield Member each funded its share of the purchase price, approximately $319.9 million and $318.6 million, respectively, through contributions to Black Diamond. Noble Member funded its share of the purchase price through a combination of cash on hand and borrowings under its revolving credit facility.

In addition to the payment to the Seller, Black Diamond, through an additional contribution from Greenfield Member, paid PDC Energy, Inc. (PDC Energy) approximately $24.1 million to expand PDC Energy’s acreage dedication as well as extend the duration of the acreage dedication by five years to approximately 12 years. In accordance with the limited liability company agreement of Black Diamond, Noble Member is to receive a 54.4% equity ownership interest in Black Diamond and Greenfield Member is to receive a 45.6% equity ownership interest in Black Diamond. Noble Member’s agreed equity ownership interest includes a 4.4% equity ownership interest promote which will vest only after Noble Member is allocated an amount of gross revenue equal to the contributions by Greenfield Member in excess of its agreed equity ownership interest.

We serve as the operator of the Black Diamond system. In connection with the Black Diamond Acquisition, we acquired a large-scale integrated gathering system located in the DJ Basin with approximately 160 miles of pipeline in operation and delivery capacity of approximately 300 MBbl/d as well as approximately 141,000 dedicated acres from six customers under fixed-fee arrangements. See Item 8. Financial Statements and Supplementary Data – Note 3. Acquisition.

Subsequent to the closing of the Black Diamond Acquisition, we secured additional long-term dedications for the Black Diamond system, representing more than 200 wells across approximately 17,000 incremental acres. The additional dedications come from an existing third party customer on the system as well as a new third-party customer and increased total acreage dedicated to the Black Diamond system by 12% to approximately 158,000 acres.

Revolving Credit Facility Amendments

On January 31, 2018, in connection with the closing of the Black Diamond Acquisition, we entered into an amendment to increase the capacity on our revolving credit facility from $350 million to $530 million. On March 9, 2018, we entered into an additional amendment to extend the maturity of the facility to March 9, 2023 and increase the borrowing capacity to $800 million. See Item 8. Financial Statements and Supplementary Data – Note 8. Long-Term Debt.

Term Loan Credit Facility

On July 31, 2018, we entered into a three year senior unsecured term loan credit facility that permits aggregate borrowings of up to $500 million. Proceeds from the term loan credit facility were primarily used to repay a portion of the outstanding borrowings under our revolving credit facility and pay fees and expenses in connection with the term loan credit facility transactions. See Item 8. Financial Statements and Supplementary Data – Note 8. Long-Term Debt.

EPIC Equity Interests

On August 2, 2018, Noble assigned its option with EPIC Midstream Holdings, LP (EPIC) to acquire a 15% equity interest in the EPIC Y-Grade Pipeline to the Partnership. On January 31, 2019, Noble assigned its option to acquire a 30% equity interest in the EPIC Crude Oil Pipeline to the Partnership. Both options were set to expire February 1, 2019.

On January 31, 2019, the Partnership exercised and closed its option with EPIC to acquire the equity interest in the EPIC Y-Grade Pipeline. At closing, we made cash contributions of approximately $103 million. Our total cash contributions are expected to be approximately $165 million to $180 million for the EPIC Y-Grade Pipeline, with substantially all of the cash contributions in 2019. We intend to fund our cash contributions for the EPIC Y-Grade Pipeline with our revolving credit facility. The EPIC Y-Grade Pipeline is an approximately 700-mile pipeline linking NGL reserves in the Permian Basin and Eagle Ford Shale to Gulf Coast refiners, petrochemical companies, and export markets. The pipeline will have a throughput capacity of approximately 440 MBbl/d with multiple origin points.

Also on January 31, 2019, the Partnership exercised its option to acquire the equity interest in the EPIC Crude Oil Pipeline. Closing of the Partnership’s equity interest in the EPIC Crude Oil Pipeline is expected to occur later in first quarter 2019, subject to certain conditions precedent. Our total cash contributions are expected to be approximately $330 million to $350 million for the EPIC Crude Pipeline, with substantially all of the cash contributions in 2019. We intend to fund our cash

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contributions for the EPIC Crude Pipeline with our revolving credit facility and other sources of funding. The planned EPIC Crude Oil Pipeline will be a 30-inch pipeline with a capacity of 590 MBbl/d from the Delaware Basin to the Gulf Coast.

Delaware Crossing Joint Venture

On October 2, 2018, we entered into a non-binding letter of intent with Salt Creek Midstream LLC (Salt Creek) to form a 50/50 joint venture to construct a crude oil pipeline system with a capacity of 160 MBbl/d in the Delaware Basin. On February 7, 2019, we executed definitive agreements and completed the formation of Delaware Crossing LLC (Delaware Crossing Joint Venture). As Salt Creek has commenced construction of the pipeline prior to formation, we made capital contributions of approximately $38 million at closing.

The 95-mile pipeline system will originate in Pecos County, Texas, with additional connections in Reeves County and Winkler County, Texas. The project footprint will be served by a combination of in-field crude oil gathering lines and a trunkline to a hub in Wink, Texas. The project is underpinned by approximately 192,000 dedicated gross acres and nearly 100 miles of pipeline in Pecos, Reeves, Ward and Winkler Counties, Texas. The pipeline is expected to be operational in the third quarter of 2019.

5

Organizational Structure

DevCo Ownership Interests

On September 20, 2016, we completed our initial public offering (the IPO). In connection with the IPO, Noble contributed to us (i) ownership interests in certain development companies (DevCos) which serve specific areas and integrated development plan (IDP) areas and (ii) a 3.33% ownership interest (the White Cliffs Interest) in White Cliffs Pipeline L.L.C. (White Cliffs). The ownership interests in the DevCos, together with the White Cliffs Interest, are referred to collectively as the Contributed Businesses.

Our DevCo structure provides multiple avenues for organic and drop down growth. The following table provides a summary of our assets, services and customers, along with our ownership of these assets, as of December 31, 2018:

DevCo	NBLX Ownership	Areas Served	NBLX Dedicated Service	Customers
Colorado River DevCo LP	100%	Wells Ranch IDP (DJ Basin) East Pony (DJ Basin) All Noble DJ Basin Acreage	Crude Oil Gathering Natural Gas Gathering Water Services Crude Oil Gathering Crude Oil Treating	Noble Noble Noble
San Juan River DevCo LP	25%	East Pony IDP (DJ Basin)	Water Services	Noble
Green River DevCo LP	25%	Mustang IDP (DJ Basin)(1)	Crude Oil Gathering Natural Gas Gathering Water Services	Noble
Laramie River DevCo LP	100%	Greeley Crescent IDP (DJ Basin)	Crude Oil Gathering Water Services	Noble and Unaffiliated Third Party
	54.4%	Black Diamond Dedication Area (DJ Basin)(2)	Crude Oil Gathering Natural Gas Gathering	Unaffiliated Third Parties
Blanco River DevCo LP	40%	Delaware Basin	Crude Oil Gathering Natural Gas Gathering Water Services	Noble and Unaffiliated Third Parties(3)
Gunnison River DevCo LP	5%	Bronco IDP (DJ Basin)(4)	Crude Oil Gathering Water Services	Noble(4)
Trinity River DevCo LLC(7)	100%	Delaware Basin	Natural Gas Compression Crude Oil Transmission(5)	Noble

⁽¹⁾  During 2018, we completed the crude oil, natural gas and produced water gathering system in the Mustang IDP area of the DJ Basin (Mustang IDP) and continued expansion of our fresh water delivery system.

⁽²⁾  Our interest in Black Diamond is owned through the Laramie River DevCo LP. In connection with the Black Diamond Acquisition, we acquired a large-scale integrated gathering system located in the DJ Basin with approximately 160 miles of pipeline in operation and delivery capacity of approximately 300 MBbl/d as well as approximately 141,000 dedicated acres. Subsequent to the closing of the Black Diamond Acquisition, we secured additional long-term dedications, representing more than 200 future wells across approximately 17,000 incremental acres. The additional dedications come from an existing third party customer on the system as well as a new third party customer.

⁽³⁾  During 2018, we received a third party producer's activity set and development plan for approximately 13,000 acres dedicated to us in Reeves County, Texas, for crude oil, natural gas and produced water gathering services. We commenced services during 2018.

⁽⁴⁾  We currently have no midstream infrastructure assets in the Bronco IDP. Our assets in the Bronco IDP currently consist primarily of dedications to us for future production in this IDP area.

⁽⁵⁾  Trinity River DevCo LLC owns our 50% ownership interest in the Advantage Joint Venture (as defined below). Crude oil produced from Noble’s legacy 47,000 Delaware Basin net acres is dedicated to the Advantage system.

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Rights of First Refusal (ROFR)

Noble has granted us a ROFR on the right to provide midstream services on certain acreage described below and on the right to acquire certain midstream assets. The following table provides a summary of the ROFR assets and ROFR services granted to us by Noble as well as the net acreage covered by our ROFR, to the extent known as of December 31, 2018, granted to us by Noble.

Areas Served	NBLX ROFR Service	Current Status of Asset	ROFR Net Acreage
East Pony (Northern Colorado)	Natural Gas Processing Natural Gas Gathering	Operational	44,000
Eagle Ford Shale	Crude Oil Gathering Natural Gas Gathering Water Services	Operational	35,000
DJ Basin (other than dedicated above)	To the extent not already covered in dedication in the prior chart: Crude Oil Gathering Natural Gas Gathering Water Services	N/A	79,000
Delaware Basin	Water Services	In Progress	108,000
All future-acquired onshore acreage in the United States (outside of the Marcellus Shale)	Crude Oil Gathering Natural Gas Gathering Natural Gas Processing Water Services	N/A	N/A

Rights of First Offer (ROFO)

Noble has granted us a ROFO with respect to its retained interests in the DevCos through which we conduct our midstream services. Pursuant to our ROFO, before Noble can offer any of its retained interests in the DevCos to any third party, Noble must allow us to make an offer to purchase these interests. We believe that the ROFO on Noble’s retained interests in our DevCos will provide us an opportunity to develop organic growth with potentially lower development capital costs. We are under no obligation to purchase any of Noble’s retained interests in the DevCos, and Noble is only under an obligation to permit us to make an offer on these interests to the extent that Noble elects to sell these midstream assets to a third party.

7

Organizational Structure

The following diagram depicts our organizational structure as of December 31, 2018.

Our Relationship with Noble

One of our principal strengths is our relationship with Noble. Given Noble’s significant ownership interest in us 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. Noble accounts for a substantial portion of our revenues and the loss of Noble as a customer would have a material adverse effect on us. See Item 1A. Risk Factors.

8

Areas of Operation

The following diagram illustrates our areas of operations as of December 31, 2018:

9

Reportable Segments

We manage our operations by the nature of the services we offer. Our reportable segments comprise the structure used to make key operating decisions and assess performance. We are organized into the following reportable segments: Gathering Systems (crude oil, natural gas and produced water gathering, crude oil treating and crude oil sales), Fresh Water Delivery, and Investments and Other. We often refer to services of our Gathering Systems and Fresh Water Delivery segments collectively as our midstream services. The Investments and Other segment includes our investments in the Advantage Joint Venture and White Cliffs Interest as well as all general Partnership activity not attributable to our DevCos. See Item 8. Financial Statements and Supplementary Data – Note 10. Segment Information.

Gathering Systems

Crude Oil Gathering

Our crude oil gathering system in the Wells Ranch IDP area of the DJ Basin (the Wells Ranch IDP) provides approximately 71 miles of shared crude oil and produced water gathering pipelines. Our crude oil gathering assets also include 96,000 Bbls of storage capacity at the Wells Ranch Central Gathering Facility (CGF) where we are able to recover gas vapors from the crude oil and deliver this natural gas to Noble for delivery to downstream third parties.

In the East Pony IDP area of the DJ Basin (the East Pony IDP), we gather crude oil meeting pipeline specifications and deliver it through approximately 34 miles of pipeline 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 area is subject to Federal Energy Regulatory Commission (FERC) jurisdiction. See Items 1. and 2. Business and Properties - Regulations.

To service the Mustang IDP, we gather crude oil meeting pipeline specifications and deliver it through approximately 5 miles of pipeline into the Black Diamond Milton Terminal. We began gathering crude oil in the Mustang IDP in the second quarter of 2018.

To service the Greeley Crescent IDP, we gather crude oil meeting pipeline specifications for an unaffiliated third party. We deliver the gathered crude oil through approximately 42 miles of pipeline to the Grand Mesa Pipeline via the Black Diamond Lucerne Terminal and directly to the White Cliffs Pipeline.

To service the Black Diamond dedication area, we gather crude oil meeting pipeline specifications and deliver it through approximately 227 miles of pipeline to various delivery points. The Black Diamond system provides access to long-haul crude oil outlets including Grand Mesa Pipeline, Saddlehorn Pipeline, White Cliffs Pipeline and Pony Express Pipeline.

Our crude oil gathering systems in the Delaware Basin include approximately 91 miles of pipeline. We gather off-spec crude oil from well pad facilities, which is delivered to various CGFs. We have five operational CGFs in the Delaware Basin. The Billy Miner I and Jesse James CGFs were completed during 2017 and the Coronado, Collier and Billy Miner Train II CGFs were completed during 2018. The CGFs stabilize the crude oil to be sent downstream to pipelines leaving the Delaware Basin.

The table below sets forth our crude oil gathering capacity and operations as of and for the dates indicated.

	Throughput Capacity (Bbl/d)		Average Daily Throughput (Bbl/d)		Number of Horizontal Wells
	As of December 31,		Year Ended December 31,		As of December 31,
	2018	2017	2018	2017	2018	2017
Wells Ranch IDP	50,000	50,000	38,383	33,703	453	407
East Pony IDP	85,000	85,000	23,872	22,828	267	249
Mustang IDP	60,000	—	6,519	—	30	—
Greeley Crescent IDP	60,000	60,000	14,792	5,333	191	60
Black Diamond System	300,000	—	59,529	—	699	—
Delaware Basin (1)	70,000	30,000	28,235	3,791	86	19

⁽¹⁾  The Billy Miner I and Jesse James CGFs each have throughput capacity of 15 MBbl/d. The Billy Miner II and Collier CGFs each have throughput capacity of 10 MBbl/d. The Coronado CGF has throughput capacity of 20 MBbl/d.

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Crude Oil Treating

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 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 each 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 the services provided at the crude oil treating facilities, Noble pays monthly fees based on the number of producing vertical and 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 below sets forth the number of producing vertical and horizontal wells in the DJ Basin that are not connected to our gathering system and are subject to a monthly fee as of the dates indicated.

	Number of Wells Subject to Monthly Fee
	As of December 31, 2018	As of December 31, 2017
Producing Vertical Wells	1,257	1,753
Producing Horizontal Wells	406	471

Natural Gas Gathering

Our natural gas infrastructure assets in the Wells Ranch IDP consist of the Wells Ranch CGF and an approximately 64-mile natural gas pipeline system. The natural gas gathering system that services the production from the Wells Ranch IDP collects natural gas from separator facilities located at or near the wellhead and delivers the natural 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 or other delivery points, as applicable, we deliver the natural gas for further processing by third parties.

Our natural gas infrastructure in the Mustang IDP consists of an approximately 15-mile natural gas pipeline system. The natural gas gathering system that services production from the Mustang IDP collects natural gas from separator facilities located at or near the wellhead and delivers the natural gas to delivery points within the Mustang IDP. We began gathering natural gas in the Mustang IDP in the second quarter of 2018.

Our natural gas infrastructure assets in the Delaware Basin consist of five CGFs as well as an approximately 68-mile natural gas pipeline system servicing production from the Delaware Basin. The natural gas gathering system that services the production from the Delaware Basin collects natural gas from the wellhead from a high pressure separator and sends it to various CGFs. The CGFs dehydrate the natural gas, compress it, and send it downstream for processing.

To service the Black Diamond dedication area, our natural gas infrastructure consists of pipeline segments that collect natural gas from the wellhead and deliver it to third party natural gas processing plants. We gather a de minimis amount of natural gas within the Black Diamond dedication area.

The table below sets forth our natural gas gathering capacity and operations as of and for the dates indicated.

	Throughput Capacity (Mcf/d) (1)		Average Daily Throughput (MMBtu/d)		Number of Horizontal Wells
	As of December 31,		Year Ended December 31,		As of December 31,
	2018	2017	2018	2017	2018	2017
Wells Ranch IDP	200,000	150,000	221,942	172,284	453	426
Mustang IDP	200,000	—	12,934	—	30	—
Delaware Basin (2)	146,000	60,000	74,120	8,634	86	19

⁽¹⁾  To convert cubic feet to British thermal units, multiply cubic feet by 1.3.  

⁽²⁾  Each CGF has a throughput capacity of 30 MMcf/d, with the exception of the Jesse James CGF, which has a throughput capacity of 26 MMcf/d.

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.

Produced Water Gathering

Our produced water gathering system in the Wells Ranch IDP gathers and processes liquids produced from operations and consists of a combination of separation and storage facilities, and permanent pipelines, as well as pumps to transport produced

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water to disposal facilities. We operate an approximately 71-mile gathering pipeline system (which is a shared crude oil and produced water gathering pipeline) servicing the Wells Ranch IDP. Crude oil and produced water 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 produced water liquid stream is separated, stored, and treated before the produced water is delivered to a third party pipeline for disposal. The Wells Ranch CGF has the capacity to store up to 32,000 Bbls of produced water while awaiting delivery to a disposal facility.

Our produced water gathering system in the Mustang IDP gathers liquids produced from operations and consists of a combination of pumps and permanent pipelines to transport produced water to disposal facilities. We operate an approximately 9-mile gathering pipeline system servicing the Mustang IDP. We began gathering produced water in the Mustang IDP in the second quarter of 2018.

Our produced water gathering system in the Greeley Crescent IDP gathers liquids produced from operations and consists of a combination of pumps and permanent pipelines to transport produced water to disposal facilities. We operate an approximately 20-mile gathering pipeline system servicing the Greeley Crescent IDP.

Our produced water gathering system in the Delaware Basin gathers and processes liquids produced from operations and consists of stabilization facilities, and permanent pipelines, as well as pumps to transport produced water to disposal facilities. We operate an approximately 78-mile gathering pipeline system servicing the Delaware Basin. At our CGFs, the incoming produced water is skimmed and pumped downstream to the disposal wells.

We enter into and manage contracts with third party providers for any produced water services that we do not perform ourselves.

The table below sets forth our produced water capacity and operations as of and for the dates indicated.

	Throughput Capacity (Bbl/d)		Average Daily Throughput (Bbl/d)		Number of Horizontal Wells
	As of December 31,		Year Ended December 31,		As of December 31,
	2018	2017	2018	2017	2018	2017
Wells Ranch IDP	30,000	30,000	16,984	14,097	453	407
Mustang IDP	30,000	—	4,874	—	30	—
Greeley Crescent IDP	20,000	20,000	8,045	2,338	191	60
Delaware Basin (1)	240,000	60,000	71,297	7,996	86	19

⁽¹⁾  The Billy Miner I and Jesse James CGFs each have throughput capacity of 30 MBbl/d. The Billy Miner II, Collier and Coronado CGFs each have throughput capacity of 60 MBbl/d.

Fresh Water Delivery

Our fresh water systems provide services for both treated produced water 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 our customers’ drilling and completion operations.

Our fresh water systems in the DJ Basin contain an approximately 70-mile fresh water distribution system made up of permanent buried pipelines, 9 miles of which service the East Pony IDP, 22 miles of which service the Wells Ranch IDP, 15 miles which service the Mustang IDP, and 24 miles of which serve the Greeley Crescent IDP. In addition, our fresh water systems include fresh water storage facilities in the Wells Ranch IDP, East Pony IDP, and Mustang IDP, as well as temporary pipelines and pumping stations to transport fresh water throughout the pipeline networks. These systems are designed to deliver water on demand to hydraulic fracturing operations and reduce the costs of transporting water long distances by reducing or eliminating most trucking costs. The fresh water systems provide storage capacity that segregates raw fresh water from produced water that has been treated.

We do not own or hold title to the water nor do we own or operate fresh water sources, but instead our services are focused on the storage and distribution of the fresh water delivered to us by our customers.

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The table below sets forth our fresh water delivery services capacity and operations as of and for the dates indicated.

	Distribution Capacity (Bpm)		Average Daily Throughput (Bbl/d)		Storage Capacity (Bbls)
	As of December 31,		Year Ended December 31,		As of December 31,
	2018	2017	2018	2017	2018	2017
Wells Ranch IDP	170	170	47,012	83,856	500,000	500,000
East Pony IDP (1)	160	160	—	34,676	550,000	550,000
Mustang IDP	180	180	68,312	—	1,180,000	1,180,000
Greeley Crescent IDP	120	120	60,430	37,458	1,600,000	1,600,000

⁽¹⁾  During 2018, no fresh water was delivered due to the timing of well completion activity by Noble.

Investments and Other

Our Investments and Other segment includes our investments in the Advantage Joint Venture and White Cliffs Interest as well as all general Partnership activity not attributable to our DevCos.

We own a 50% ownership interest in Advantage Pipeline, L.L.C., (the Advantage Joint Venture). We serve as the operator of the Advantage system, which includes a 70-mile crude oil pipeline in the Southern Delaware Basin from Reeves County, Texas to Crane County, Texas, with a capacity of 200 MBbl/d and 490,000 barrels of storage capacity. Crude oil throughput volumes during 2018 averaged 107 MBbl/d.

We own a 3.33% ownership interest in White Cliffs. The White Cliffs pipeline system (the White Cliffs Pipeline) consists of two 527-mile crude oil pipelines that extend from the DJ Basin to Cushing, Oklahoma, with a capacity of approximately 215,000 Bbl/d.

Regulations

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 the Hazardous Liquids Pipeline Safety Act of 1979, or 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 are also subject to the Natural Gas Pipeline Safety Act of 1968, or 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 of 2002 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 Pipeline and Hazardous Materials Safety Administration, or PHMSA, has developed regulations implementing the Pipeline Safety Improvement Act of 2002 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, Regulatory Certainty, and Job Creation Act of 2011, also known as the Pipeline Safety and Job Creation Act, enacted in 2012, amended the HLPSA and NGPSA and increased safety regulation. This legislation 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.

In addition, in May 2016, PHMSA proposed rules that would, if adopted, impose more stringent requirements for certain natural gas lines. Among other things, the proposed rulemaking would extend certain of PHMSA’s current regulatory safety programs for gas pipelines beyond ‘‘high consequence areas’’ to cover gas pipelines found in newly defined ‘‘moderate consequence areas’’ that contain as few as five dwellings within the potential impact area and would also require gas pipelines installed before 1970 that are currently exempted from certain pressure testing obligations to be tested to determine their

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maximum allowable operating pressures, or MAOP. Other new requirements proposed by PHMSA under rulemaking would require pipeline operators to: report to PHMSA in the event of certain MAOP exceedances; strengthen PHMSA integrity management requirements; consider seismicity in evaluating threats to a pipeline; conduct hydrostatic testing for all pipeline segments manufactured using longitudinal seam welds; and use more detailed guidance from PHMSA in the selection of assessment methods to inspect pipelines. The proposed rulemaking also seeks to impose a number of requirements on natural gas gathering lines. Issuance of the final rule remains pending. PHMSA has announced its intention to divide the proposed rule into three parts and issue three separate final rulemakings in 2019. Part I is expected to address the expansion of risk assessment and MAOP requirements (expected issuance in March 2019); Part II is expected to address the expansion of integrity management program regulations (expected issuance in June 2019); and Part III is expected to expand the regulation of gas gathering lines (expected issuance in August 2019). Additionally, in January 2017, PHMSA finalized regulations for hazardous liquid pipelines that significantly extend and expand the reach of certain PHMSA integrity management requirements (i.e., periodic assessments, leak detection and repairs), regardless of the pipeline’s proximity to a high consequence area. However, PHMSA delayed publication due to the change in U.S. Presidential administrations, and the final rule is not expected to be published in the Federal Register until 2019. The final rule would also impose new reporting requirements for certain unregulated pipelines, including all hazardous liquid gathering lines. Extending the integrity management requirements to our gathering pipelines will 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 statutes, 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 Colorado Public Utilities 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 Environmental Protection Agency, or EPA, community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable 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, or CAA, to prevent the accidental release of extremely hazardous substances. The EPA finalized revisions to its Risk Management Program, or RMP, rules in January 2017. The final rules include requirements to: (i) complete third-party audits of an RMP program following an accident; (ii) consider inherently safer technology during process hazard assessments; (iii) conduct root cause analysis assessing how management failures lead to the incident; (iv) take corrective actions for the root cause identified; and (v) impose broad information-sharing requirements with emergency planners and the public and require joint emergency response exercises with local responders. In June 2017, the EPA issued a stay of the revised RMP requirements until 2019, which was immediately challenged by environmental groups. A final decision remains pending. However, pursuant to the January 2017 rulemaking, many of the revised requirements do not come become effective until 2021. We have an internal program of inspection designed to monitor and enforce compliance with safeguard and security requirements.

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

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FERC jurisdiction. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services has been the subject of frequent 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 $1,238,271 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 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. 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 two years prior to the filing of a complaint. The rates charged for crude oil pipeline services are generally increased annually 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 Producer Price Index, or 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 December 17, 2015, the FERC issued an order establishing a new index level of PPI plus 1.23% for the five-year period commencing July 1, 2016. As an alternative to this indexing methodology, pipelines may also choose to support changes

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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, the crude oil gathering system servicing the East Pony IDP transports crude oil in interstate commerce. In addition, the Black Diamond crude oil gathering system, Empire Pipeline crude oil gathering system and Green River crude oil gathering system, completed in 2018, transport crude oil in interstate commerce. As part of the Black Diamond Acquisition, the Saddle Butte crude oil gathering system’s name was changed to the Black Diamond crude oil gathering system. We have been granted a temporary waiver of the tariff and reporting requirements for these crude oil gathering systems. Therefore, currently the FERC’s regulation of these two crude oil gathering systems is limited to requiring us to maintain our books and records consistent with the FERC’s record keeping requirements. The classification and regulation of these crude oil gathering pipelines are subject to change based on changed circumstances on the pipeline or 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. If it is determined that some 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, such systems could be subject to cost-of-service rates and common carrier requirements that could adversely affect the results of our operations on and revenues associated with those systems.

In addition to the crude oil gathering systems listed above, we own interests in other crude oil gathering pipelines that do not provide interstate services and are not subject to regulation by the FERC. We are the parent owner of two pipelines regulated by the Railroad Commission of Texas (the RRC), the Blanco River Pipeline and the Advantage Pipeline. The Blanco River Pipeline is owned by our subsidiary, Blanco River DevCo LP (Blanco River). We jointly own the Advantage Pipeline with Plains Pipeline, L.P., through our subsidiary, Trinity River DevCo LLC. Blanco River and the Advantage Pipeline have common-carrier pipeline tariffs on file with the RRC. 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 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 and revenue associated with those systems.

We also own two marketing affiliates, Optimized Energy Solutions, LLC, which was acquired through the 2018 Black Diamond Acquisition and is a shipper on the Black Diamond crude oil gathering system, and Advantage Pipeline Logistics LLC, a shipper on the Advantage Pipeline crude oil gathering system. On November 22, 2017, in FERC Docket No. OR17-2-000, the FERC issued an Order on Petition for Declaratory Order addressing whether certain specific hypothetical transactions between a petroleum liquids pipeline and its marketing affiliate proposed by the petitioner, Magellan Midstream Partners, L.P., would violate the requirements of the ICA or the FERC’s regulations and policies. The FERC concluded that certain transactions proposed by the petitioner could be inconsistent with the ICA and the FERC’s policies. Various market participants filed requests for clarification or, in the alternative, rehearing of the November 22, 2017 declaratory order. On January 22, 2018, the FERC issued an order granting rehearing for further consideration, which afforded the FERC additional time to consider and rule on the pending clarification/rehearing requests. The outcome of this proceeding and any related proceeding(s) may require us to modify the business practices between our petroleum liquids pipelines regulated by FERC and their respective marketing affiliates. To the extent the foregoing proceedings result in substantial new restrictions on the transactions between petroleum liquids pipelines and their affiliated shippers, the business activities of Optimized Energy Solutions, LLC, and Advantage Pipeline Logistics LLC, could be affected.

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. Noble has been an active industry participant in discussions with local governments in Colorado, civic entities, and environmental organizations on initiatives relating to oil and gas development in communities, which discussions can directly or indirectly affect public policy relating to midstream services.

More recently, the oil and gas industry in Colorado has historically encountered initiatives to regulate, limit or ban hydraulic fracturing or other facets of crude oil and natural gas exploration, development or operations. For example, in November 2018, a majority of Colorado voters voted against Proposition #112, which, if passed, would have increased the set-back zone for new “oil and gas development” to 2,500 feet. The adoption of Proposition #112 could have significantly limited, or in some cases prevented, the future development of crude oil and natural gas in areas where our customers currently conduct operations, which could have simultaneously curtailed demand for our midstream services within the state. Colorado’s new governor, Jared Polis, has previously supported enhanced setback requirements. We cannot predict whether any similar ballot initiatives will be

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proposed in the future or what actions the new governor may take with respect to the regulation of hydraulic fracturing. To the extent that the State of Colorado adopts new regulations that impact our customers, the impact of these regulations on our customers’ production activity may result in decreased demand for the midstream services we provide.

We continue to monitor proposed and new regulations and legislation in all our operating jurisdictions to assess the potential impact on our company. Concurrently, we are engaged in extensive public education and outreach efforts with the goal of engaging and educating the general public and communities about the economic and environmental benefits of safe and responsible crude oil and natural gas development.

Environmental Matters

General

Our gathering pipelines, crude oil treating facilities and produced water 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, expansion, modification and operational activities based on National Ambient Air Quality Standards (NAAQS) and 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 has been 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 suspension of activities or 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.

Climate Change and Air Quality Standards

Our operations are subject to the CAA and comparable state and local requirements. The CAA contains provisions that may result in the imposition of certain pollution control requirements with respect to air emissions from our operations. We may be required to incur certain capital expenditures for air pollution control equipment in connection with maintaining or obtaining pre-construction and operating permits and approvals addressing other air emission-related issues.

For example, in February 2014, Colorado’s Air Quality Control Commission approved comprehensive changes to Regulation 7 that governs emissions from crude oil and natural gas activities, including the nation’s first-ever regulations designed to detect and reduce methane emissions. The EPA has also acted to add requirements that control methane emissions from crude oil and natural gas activities. In June 2016, the EPA finalized these new regulations by setting methane emission standards for new and modified oil and natural gas production and natural gas processing and transmission facilities. Following the change in administration, there have been attempts to modify these regulations, and litigation is ongoing. As a result, future

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implementation of the 2016 standards is uncertain at this time. To the extent implemented, these regulations could result in increased costs for our operations and for the operations of Noble. Separately, the EPA finalized rules in June 2016 that resolved how oil and gas production facility emissions must be aggregated under the CAA permitting program. This action clarified certain permitting requirements, yet could still impact permitting and compliance costs.

Moreover, on June 2, 2015, the U.S. District Court of Colorado entered as a final judgment (the “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 after the Consent Decree became effective and remain subject to such Consent Decree. The Consent Decree requires, in accordance with a 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.

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 response to findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment, the EPA has adopted regulations under existing provisions of the 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. We currently do not operate any Title V sources, but our facilities could become subject to Title V permitting requirements in the future. 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 monitoring and reporting of GHG emissions from specified onshore crude oil and natural gas production sources in the U.S. on an annual basis.

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 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. Notwithstanding potential risks related to climate change, the International Energy Agency estimates that oil and gas will continue to represent a major share of global energy use through 2040, and other private sector studies project continued growth in demand for the next two decades. However, recent activism directed at shifting funding away from companies with energy-related assets could result in limitations or restrictions on certain sources of funding for the energy sector. Moreover, activist shareholders have introduced proposals that may seek to force companies to adopt aggressive emission reduction targets or to shift away from more carbon-intensive activities. While we cannot predict the outcomes of such proposals, they could ultimately make it more difficult for operators to engage in exploration and production activities. Finally, it should be noted that many 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 a materially adverse effect on our operations or Noble’s exploration and production operations, which in turn could affect demand for our services.

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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, 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 crude oil and 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, 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. For example, in December 2016, the EPA and environmental groups entered into a consent decree to address EPA’s alleged failure to timely assess its RCRA Subtitle D criteria regulations exempting certain exploration and production related oil and gas wastes from regulation as hazardous wastes. The consent decree requires EPA to propose a rulemaking no later than March 15, 2019 for any revisions relating to oil and gas wastes or to sign a determination that revision of the regulations is not necessary. 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, 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.” The Clean Water Rule has been challenged in multiple federal courts, and following the change in presidential administration, the agencies have attempted to roll back the regulation. On December 11, 2018, the EPA and the Corps proposed changes to regulations under the CWA that would provide discrete categories of jurisdictional waters and tests for determining whether a particular waterbody meets any of those classifications. Several groups have already announced their intentions to challenge the proposed rule. As a result the scope of jurisdiction under the CWA is uncertain at this time. To the extent a 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.

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

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that require us to have permits in order to discharge certain types of 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. 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, 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 under OPA.

Colorado Water Quality Control Act

In January 2017, we received a Notice of Violation/Cease and Desist Order, or NOV/CDO, advising us of alleged violations of the Colorado Water Quality Control Act, or CWQCA, and its implementing regulations as it relates to construction activities associated with oil and gas exploration and/or production within our Wells Ranch IDP located in Weld County, Colorado, or Permit.  The NOV/CDO further orders us to cease and desist from all violations of the CWQCA, the regulations and the Permit and to undertake certain corrective actions. In October 2018, we met with enforcement staff at the Colorado Department of Public Health and Environment to discuss a potential settlement of the alleged violations. Given the ongoing status of such settlement discussions, we are unable to predict the ultimate outcome of this action at this time but believe that the resolution of this action will not have a material adverse effect on our financial position, results of operations or cash flows.

Hydraulic Fracturing

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 shale, that require hydraulic fracturing as part of the completion process. The majority of our fresh water services business is related to the storage and transportation of water for use in hydraulic fracturing. Hydraulic fracturing is a well stimulation process that utilizes large volumes of water and sand combined with fracturing chemical additives that are pumped into a well 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 and local governments, including those in which we operate, have adopted, and other states are considering adopting, regulations that could impose more stringent chemical disclosure or well construction requirements on hydraulic fracturing operations, or otherwise seek to ban some or all of these activities. For example, in Colorado, state ballot and other regulatory initiatives have been proposed from time to time to impose additional restrictions or bans on hydraulic fracturing or other facets of crude oil and natural gas exploration, production or related activities. For example, in November 2018, Colorado voters considered a ballot measure known as Proposition #112 that, if passed, would have significantly limited, or even prevented, the future development of crude oil and natural gas in areas where we perform midstream services by imposing strict setback requirements for operations near occupied structures or environmental sensitive areas. While the proposition was not approved by voters, Colorado’s new governor, Jared Polis, has previously supported enhanced setback requirements. We cannot predict whether any similar ballot initiatives will be proposed in the future or what actions the new Governor may take with respect to the regulation of hydraulic fracturing. Any new limitations or prohibitions on oil and gas exploration and production activities could result in decreased demand for our midstream services and have a material adverse effect on our cash flows, results of operations, financial condition, and liquidity. At the federal level, however, several agencies have asserted jurisdiction over certain aspects of the hydraulic fracturing process. For example, the EPA, has moved forward with various regulatory actions, including the issuance of new regulations requiring green completions for hydraulically fractured wells, and emission requirements for certain midstream equipment. Also, in June 2016, the EPA finalized rules which 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. 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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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. However, listings of additional species, such as the greater sage grouse, under the ESA and similar state laws could result in the imposition of restrictions on our operations and consequently have a material 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.

Title to Our Properties

Many of 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 December of 2015. Since that time, we have been acquiring additional Real Estate Agreements in our own name or by transfer from Noble. The Real Estate Agreements and related interests that we have taken by assignment were acquired 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. With respect to our third party customer, we will not take title to the water that we handle and will only have the right to receive, deliver and handle such water.

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 the IPO. Noble’s indemnification obligation will be limited to losses for which we notify Noble prior to the third anniversary of the closing of the IPO and will be subject to a $500,000 aggregate deductible before we are entitled to indemnification.

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 and other customers to execute their drilling and development plans and increase operating expenses associated with repairs or anti-freezing operations.

Customers

For the year ended December 31, 2018, revenues from Noble and its affiliates comprised 79% and 57% of our midstream services revenues and total revenues, respectively. For the year ended December 31, 2018, revenues from a single third party, Stanchion Energy, LLC, customer comprised 66% and 19% of our crude oil sales revenues and total revenues, respectively.

For the years ended December 31, 2017 and 2016, revenues from Noble and its affiliates comprised 94% and 100% of our total revenues, respectively.

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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. Although Noble will continue to use third party service providers for certain midstream services in the Delaware Basin until the expiration or termination of certain pre-existing dedications, we will not compete for Noble’s business in the Delaware Basin after the expiration of such dedications. However, we will face competition in providing services on the acreage that is subject to our ROFR rights because Noble is only required to dedicate such acreage to us if we are able to offer services to Noble on the same or better terms as the applicable third party service provider.

As we continue to expand our midstream services, 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 continue to provide midstream services to additional 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.

Employees

The officers of our General Partner manage our operations and activities. All of the employees required to conduct and support our operations are employed by Noble and are subject to the operational services and secondment agreement that we entered into with Noble in connection with our IPO. As of December 31, 2018, Noble employed approximately 160 people who provide direct support to our operations pursuant to the operational services and secondment agreement.

Office

The principal office of our Partnership is located at 1001 Noble Energy Way, Houston, Texas 77070.

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 have 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 is purchased through a captive insurance company that is an affiliate of Noble. Most of this captive insurance is reinsured into the commercial market. To the extent Noble experiences covered losses under the excess liability insurance policies, the limit of our coverage for potential losses may be decreased.

Available Information

Our Common Units are listed and traded on the NYSE under the symbol “NBLX.” Our website is www.nblmidstream.com. We make our periodic reports and other information filed with or furnished to the U.S. Securities and Exchange Commission, or 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. Alternatively, you may access these reports at the SEC’s website at www.sec.gov. Information on our website or any other website is not incorporated by reference into this Annual Report and does not constitute a part of this Annual Report.

Our Audit Committee charter is also posted on our website under “About Us – Corporate Governance” and is available in print upon request made by any unitholder to the Investor Relations Department. Copies of our Code of Conduct and Code of Ethics for Financial Officers, or the Codes, are also posted on our website under the “Corporate Governance” section. Within the time period required by the SEC and the NYSE, as applicable, we will post on our website (www.nblmidstream.com/about-us/corporate-governance/) any modifications to the Codes and any waivers applicable to senior officers as defined in the applicable Code, as required by the Sarbanes-Oxley Act of 2002.

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Item 1A.    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 and all other information set forth in this Annual Report.

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 a substantial portion 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, produced water 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.

A substantial portion of our commercial agreements are with Noble or its affiliates. Accordingly, because we derive a substantial portion 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 or enforcement of existing 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 cancellation of planned development, breach of commitments with respect to future dedications; and other non-payment or non-performance by Noble, including with respect to our commercial agreements, which do not contain minimum volume commitments. Noble is currently operating two drilling rigs in the DJ Basin and five drilling rigs in the Delaware Basin. A 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 commercial agreements. Any material non-payment or non-performance by Noble under our commercial 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. Our long-term commercial agreements with Noble carry initial terms for 15 years, of which 12 years remain, 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 commercial 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.

In addition to our commercial agreements with Noble, we provide midstream services and crude oil sales for unaffiliated, non-investment grade third party customers. We may engage in significant business with new third party customers or enter into material commercial contracts with customers for which we do not have material commercial arrangements or commitments today and who may not have investment grade credit ratings. Each of the risks indicated above applies to our current third

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party customers and to the extent we derive substantial income from or commit to capital projects to service new or existing customers, each of the risks indicated above would apply to such arrangements and customers.

In the event any customer, including Noble, elects to sell acreage that is dedicated to us to a third party, the third party’s financial condition could be materially worse than the customer with whom we have contracted, and thus we could be subject to the nonpayment or nonperformance by the third party.

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

We may not generate sufficient distributable cash flow to enable us to make quarterly distributions to our unitholders at our current distribution rate.

We may not generate sufficient distributable cash flow to enable us to make quarterly distributions at our current distribution rate.

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 sell, the volumes of produced water we collect, clean or dispose of and the volumes of fresh water we distribute and store and the number of wells that have access to our crude oil treating facilities;

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

• our customers’ ability to fund their drilling and development plans on our dedicated acreage;

• downstream processing and transportation capacity constraints and interruptions, including the failure of our customers 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 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.

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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 our customers’ 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 and any third party customers on acreage dedicated to our midstream systems or execute agreements with other 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;

• levels of reserves;

• geologic considerations;

• changes in the strategic importance our customers assign to development in the DJ Basin or the Delaware Basin as opposed to their other operations, which could adversely affect the financial and operational resources our customers are 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 permits, the regulation of hydraulic fracturing and a governmental determination that multiple facilities are to be treated as a single source for air permitting purposes; 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 our customers do not maintain their 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 our customers assist in their drilling activities. If our customers do not maintain their drilling activities on our dedicated acreage, their demand for our fresh water services will be reduced regardless of whether we continue to provide our other midstream services on their 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.

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

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

The limited partnership agreement governing each DevCo requires that the General Partner of such DevCo cause such DevCo 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 DevCo’s business.

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The amount of cash each DevCo generates from its operations will fluctuate from quarter to quarter based on events and circumstances and the actual amount of cash each DevCos will have available for distribution to its partners, including us, also will depend on certain factors.

Our midstream assets are currently primarily located in the DJ Basin in Colorado and the Delaware Basin in Texas, making us vulnerable to risks associated with operating in a limited geographic area.

Our midstream assets are currently located primarily in the DJ Basin in Colorado and the Delaware Basin in Texas. 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 these areas caused by governmental regulation, market limitations, water shortages, drought related conditions or other weather-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 or Delaware 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 our customers will develop acreage that is dedicated to us or the areas they will decide to develop.

Our acreage dedication and commitments from our customers cover midstream services in a number of areas that are at the early stages of development, in areas that our customers are still determining whether to develop and in areas where we may have to acquire operating assets from third parties. In addition, our customers own acreage in areas that are not dedicated to us. We cannot predict which of these areas our customers will determine to develop and at what time. Our customers 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. Our customers’ decisions 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 certain acreage that Noble currently owns and on all acreage that Noble acquires onshore in the U.S., portions of this acreage may be subject to preexisting dedications that may require Noble to use third parties for midstream services.

Although Noble has granted us a ROFR to provide the midstream services covered by our commercial agreements as well as natural gas processing on all of the dedicated acreage where not all of such services are currently provided, on all of its currently owned acreage in the DJ Basin that has not yet been dedicated, on certain of its currently owned acreage in the Eagle Ford Shale and on all of its future acquired acreage onshore in the United States (other than in the Marcellus Shale), portions of this acreage may be subject to preexisting dedications, rights of first refusal, rights of first offer and other preexisting encumbrances 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 these midstream services on this acreage. Because we do not have visibility as to which acreage Noble may acquire or divest, and what existing dedications, rights of first refusal, rights of first offer or other overriding rights may exist on such acreage, we are unable to predict the value, if any, of our ROFR to provide midstream services on Noble’s acreage onshore in the United States.

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

Noble is required to offer us, prior to contracting for such opportunity with a third party, the opportunity to provide the midstream services covered by our commercial agreements, which include crude oil gathering, natural gas gathering, produced water gathering, fresh water services and crude oil treating, as well as services of a type provided at natural gas processing plants on certain acreage located in the United States that Noble currently owns or in the future acquires or develops. In addition, Noble is required to offer us, prior to contracting for such opportunity with a third party, the ownership interest in any midstream assets that are located on the acreage for which Noble has granted us a ROFR to provide services. The acreage and assets subject to this ROFR may be located in areas far from our existing infrastructure or may otherwise be undesirable in the context of our business. In addition, we can make no assurances that the terms at which Noble offers us the opportunity to provide these services or purchase these assets will be acceptable to us. Furthermore, another midstream service provider or third party may be willing to accept an offer from Noble that we are unwilling to accept. Our inability to take advantage of the opportunities with respect to such acreage or assets could adversely affect our growth strategy or our ability to maintain or increase our cash distribution level.

We may be unable to grow by acquiring the non-controlling interests in our DevCos 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

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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 DevCos. We have only a ROFO, pursuant to our omnibus agreement that requires Noble to allow us to make an offer with respect to Noble’s retained non-controlling interests in our DevCos to the extent Noble elects to sell these interests. In addition, Noble has granted us a ROFR with respect to opportunities to (1) provide services covered by our commercial agreements as well as services of a type provided at natural gas processing plants on certain acreage located in the United States that Noble currently owns or in the future acquires or develops and (2) purchase ownership interests in any assets currently owned by Noble, or in the future developed or acquired by Noble, for the purpose of providing the services described in clause (1) above, provided, that, such assets are located onshore in the United States and are not used to provide services with respect to production from the Marcellus Shale. Noble is under no obligation to sell its retained interests in our DevCos or offer to sell us additional 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 decide to sell its retained interests in our DevCos or make any offers to sell assets to us. We may never purchase all or any portion of the non-controlling interests in our DevCos or any of Noble’s retained, acquired or developed midstream assets onshore in the United States (other than in the Marcellus Shale) 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 assets or make acceptable offers for these equity interests;

• 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 Noble will decide to sell all or any portion of its non-controlling interests or will offer us any portion of its assets, and we can provide no assurance that we will be able to successfully consummate any future acquisition of all or any portion of such non-controlling interests in our DevCos or assets. Furthermore, if Noble reduces its ownership interest in us, it may be less willing to sell to us its retained non-controlling interests in our DevCos or its retained assets. In addition, except for our ROFO and ROFR, there are no restrictions on Noble’s ability to transfer its non-controlling interests in our DevCos 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 DevCos 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.

An acquisition from Noble or a third party may reduce, rather than increase, our distributable cash flow or may disrupt our business.

Even if we make acquisitions that we believe will be accretive, these acquisitions may nevertheless result in a decrease in our distributable cash flow.  Any acquisition involves potential risks that may disrupt our business, including the following, among other things:

• mistaken assumptions about volumes or the timing of those volumes, revenues or costs, including synergies;

• an inability to successfully integrate the acquired assets or businesses;

• the assumption of unknown liabilities;

• exposure to potential lawsuits;

• limitations on rights to indemnity from the seller;

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

• unforeseen difficulties operating in new geographic areas; and

• customer or key employee losses at the acquired businesses.

We may not be able to attract dedications of additional 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 continuing to diversify our customer base by identifying additional opportunities to offer services to third parties in our areas of operation. To date and over the near term, a substantial portion 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, some of our competitors for third party

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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 additional 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 additional 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 DevCos, to purchase or construct new midstream systems, or to fulfill our commitments to service acreage committed to us by our customers. 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 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.

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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, contractual, 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 and the expansion into new production areas to service Noble or our third party customer involve 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 setback requirements or expand certain facilities that are deemed to be part of a single source. Regulations clarifying how oil and gas production facility emissions must be aggregated under the CAA permitting program were finalized in June 2016. This action clarified certain permitting requirements, yet could still impact permitting and compliance costs. Moreover, Colorado has its own test for aggregating emission sources, and aggressive application of state preconstruction permitting requirements could result in delays and additional costs for midstream construction projects. Financing may not be available on economically acceptable terms or at all. As we build infrastructure to meet our customers’ needs, we may not be able to complete such projects 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. We may construct facilities to capture anticipated future production growth from Noble or another customer 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 permits or approvals, rights-of-way, surface use agreements or other real estate 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, and our fees may only be increased above the annual year-over-year increase by mutual agreement between us and our customer. If the cost of renewing or obtaining new agreements increases, our cash flows could be adversely affected.

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 or proceedings 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 can increase our cost of doing business and affect our profitability.

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

Our crude oil gathering system servicing the East Pony IDP transports crude oil in interstate commerce. In addition, the Black Diamond crude oil gathering system, Empire Pipeline crude oil gathering system and Green River crude oil gathering system, completed in 2018, transport crude oil in interstate commerce. As part of the Black Diamond Acquisition, the Saddle Butte crude oil gathering system’s name was changed to the Black Diamond crude oil gathering system.

Pipelines that transport crude oil in interstate commerce are, among other things, subject to rate regulation by the FERC, unless such rate requirements are waived. We have received a waiver of the FERC’s tariff requirements for all of these crude oil gathering systems. These temporary waivers are subject to revocation in certain circumstances. We are required to inform the FERC of any change in circumstances upon which the waivers were granted. Should the circumstances change, the FERC could find that transportation on these system no longer qualifies for a waiver. In the event that the FERC were to determine that these crude oil gathering systems no longer qualified for the waiver, we would likely be required to comply with the tariff and reporting requirements, including filing a tariff with the FERC and providing a cost justification for the applicable

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transportation rates, and providing service to all potential shippers, without undue discrimination. A revocation of the temporary waivers for these pipelines could adversely affect the results of our revenues.

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

The FERC’s ratemaking policies are subject to change and may impact the rates charged and revenues received on White Cliffs Pipeline and our gathering systems in the event the temporary waivers do not remain in effect, and any other natural gas or liquids pipeline that is determined to be under the jurisdiction of the FERC. On December 15, 2016, FERC issued a Notice of Inquiry requesting energy industry input on how FERC should address income tax allowances in cost-based rates proposed by pipeline companies organized as part of a master limited partnership. FERC’s current policy permits pipelines and storage companies to include a tax allowance in the cost-of-service used as the basis for calculating their regulated rates. For pipelines and storage companies owned by partnerships or limited liability company interests, the current tax allowance policy reflects the actual or potential income tax liability on the FERC jurisdictional income attributable to all partnership or limited liability company interests if the ultimate owner of the interest has an actual or potential income tax liability on such income. FERC issued the Notice of Inquiry in response to a remand from the U.S. Court of Appeals for the D.C. Circuit in United Airlines v. FERC, in which the court determined that FERC had not justified its conclusion that an oil pipeline organized as a partnership would not “double recover” its taxes under the current policy by both including a tax allowance in its cost-based rates and earning a return on equity calculated on a pre-tax basis. On March 15, 2018, as clarified on July 18, 2018, in a set of related issuances, FERC addressed treatment of federal income tax allowances in regulated entity rates. To the extent a regulated entity is permitted to include an income tax allowance in its cost-of-service, FERC directed entities to calculate the income tax allowance at the reduced 21% maximum corporate tax rate established by the Tax Cuts and Jobs Act of 2017. FERC also issued the Revised Policy on Treatment of Income Taxes (Revised Policy Statement) stating that it will no longer permit master limited partnerships to recover an income tax allowance in their cost-of-service rates. The FERC has noted that to the extent an entity does not include an income tax allowance in their cost-of-service rates, such entity may elect to also exclude the ADIT balance from the rate calculation. The Commission's Revised Policy Statement may result in an adverse impact on our revenues associated with the transportation and storage if we are required to set and charge cost-based rates.

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 and Job Creation Act, is the most recent federal legislation to amend the NGPSA, and the HLPSA, which are pipeline safety laws, requiring increased safety measures for natural gas and hazardous liquids pipelines. Among other things, the Pipeline Safety and Job Creation 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.

In addition, in May 2016, PHMSA proposed rules that would, if adopted, impose more stringent requirements for certain natural gas lines. Among other things, the proposed rulemaking would extend certain of PHMSA’s current regulatory safety programs for gas pipelines beyond ‘‘high consequence areas’’ to cover gas pipelines found in newly defined ‘‘moderate consequence areas’’ that contain as few as five dwellings within the potential impact area and would also require gas pipelines installed before 1970 that are currently exempted from certain pressure testing obligations to be tested to determine their MAOP. Other new requirements proposed by PHMSA under rulemaking would require pipeline operators to: report to PHMSA in the event of certain MAOP exceedances; strengthen PHMSA integrity management requirements; consider seismicity in evaluating threats to a pipeline; conduct hydrostatic testing for all pipeline segments manufactured using longitudinal seam welds; and use more detailed guidance from PHMSA in the selection of assessment methods to inspect pipelines. The proposed rulemaking also seeks to impose a number of requirements on natural gas gathering lines. Issuance of the final rule remains pending. PHMSA has announced its intention to divide the proposed rule into three parts and issue three separate final rulemakings in 2019. Part I is expected to address the expansion of risk assessment and MAOP requirements (expected issuance in March 2019); Part II is expected to address the expansion of integrity management program regulations (expected issuance in June 2019); and Part III is expected to expand the regulation of gas gathering lines (expected issuance in August 2019). Additionally, in January 2017, PHMSA finalized regulations for hazardous liquid pipelines that significantly extend and expand the reach of certain PHMSA integrity management requirements (i.e., periodic assessments, leak detection and repairs), regardless of the pipeline’s proximity to a high consequence area. The final rule would also impose new reporting requirements for certain unregulated pipelines, including all hazardous liquid gathering lines. However, PHMSA delayed publication due to the change in U.S. Presidential administrations, and the final rule is not expected to be published in the Federal Register until 2019. The safety enhancement requirements and other provisions of the Pipeline Safety and Job Creation Act as well as any implementation of PHMSA rules thereunder could require us to install new or modified safety controls, pursue additional

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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.

We may be unable to make attractive acquisitions or successfully integrate acquired businesses, assets or properties, and any inability to do so may disrupt our business and hinder our ability to grow.

We are a growth-oriented Delaware master limited partnership formed by Noble to own, operate, develop and acquire a wide range of domestic midstream infrastructure assets. Accordingly, in the future we may make acquisitions of businesses, assets or properties that we expect to complement or expand our current assets. We may not be able to identify attractive acquisition opportunities. Even if we do identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms. No assurance can be given that we will be able to identify additional suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets.

The success of any completed acquisition will depend on our ability to integrate effectively the acquired business, asset or property into our existing operations. The process of integrating acquired businesses, assets and properties may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. Our failure to achieve consolidation savings, to incorporate the acquired businesses, assets and properties into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition and results of operations.

Our investments in joint ventures involve numerous risks that may affect the ability of such joint ventures to make distributions to us.

We conduct some of our operations through joint ventures in which we share control with our joint venture participants. Our joint venture participants may have economic, business or legal interests or goals that are inconsistent with ours, or those of the joint venture. Furthermore, our joint venture participants may be unable to meet their economic or other obligations, and we may be required to fulfill those obligations alone. Failure by us, or an entity in which we have a joint venture interest, to adequately manage the risks associated with such joint ventures could have a material adverse effect on the financial condition or results of operations of our joint ventures and, in turn, our business and operations. In addition, should any of these risks materialize, it could have a material adverse effect on the ability of the joint venture to make future distributions to us.

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 existing or future agreements for our midstream services with our customers.

We currently generate the majority of our revenues pursuant to fee-based agreements under which we are paid based on volumetric fees, rather than the underlying value of the commodity. Consequently, our existing operations and cash flows have little direct exposure to commodity price risk. However, our customers are 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 maintain fee-based pricing terms on both new contracts and existing contracts for which prices have not yet been set, our efforts to negotiate such terms may not be successful, which could have a materially adverse effect on our business.

Our contracts are subject to renewal risks.

We are a party to certain long term, fixed fee contracts with terms of various durations. As these contracts expire, we will have to negotiate extensions or renewals with existing suppliers and customers or enter into new contracts with other suppliers and customers. We may not be able to obtain new contracts on favorable commercial terms, if at all. We also may be unable to maintain the economic structure of a particular contract with an existing customer or maintain the overall mix of our contract portfolio. The extension or replacement of existing contracts depends on a number of factors beyond our control, including:

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

• the macroeconomic factors affecting our current and potential customers;

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

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

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

Our inability to renew our existing contracts on terms that are favorable or to successfully manage our overall contract mix over time may have a material adverse effect on our business, results of operations and financial condition.

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

Our revolving credit facility and term loan credit facility limit our ability to, among other things:

•incur or guarantee additional debt;

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

•make certain investments and acquisitions;

•incur certain liens or permit them to exist;

•enter into certain types of transactions with affiliates;

•merge or consolidate with another company; and

•transfer, sell or otherwise dispose of assets.

Our revolving credit facility and term loan credit facility also contain covenants requiring us to maintain certain financial ratios.

The provisions of our revolving credit facility and term loan 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 revolving credit facility and term loan 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. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources.

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 that require hydraulic fracturing as part of the completion process. The majority of our fresh water services business is related to the storage and transportation of water for use in hydraulic fracturing. Hydraulic fracturing is a well stimulation process that utilizes large volumes of water and sand combined with fracturing chemical additives that are pumped into a well 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 and local governments, including those in which we operate, have adopted, and other states are considering adopting, regulations that could impose more stringent chemical disclosure or well construction requirements on hydraulic fracturing operations, or otherwise seek to ban some or all of these activities. For example, in Colorado, state ballot and other regulatory initiatives have been proposed from time to time to impose additional restrictions or bans on hydraulic fracturing or other facets of crude oil and natural gas exploration, production or related activities. For example, in November 2018, Colorado voters considered a ballot measure known as Proposition #112 that, if passed, would have significantly limited, or even prevented, the future development of crude oil and natural gas in areas where we perform midstream services by imposing strict setback requirements for operations near occupied structures or environmental sensitive areas. While the proposition was not approved by voters, Colorado’s new governor, Jared Polis, has previously supported enhanced setback requirements. We cannot predict whether any similar ballot initiatives will be proposed in the future or what actions the new Governor may take with respect to the regulation of hydraulic fracturing.

Any new limitations or prohibitions on oil and gas exploration and production activities could result in decreased demand for our midstream services and have a material adverse effect on our cash flows, results of operations, financial condition, and liquidity. At the federal level, several agencies have asserted jurisdiction over certain aspects of the hydraulic fracturing process. For example, the EPA has moved forward with various regulatory actions, including the issuance of new regulations requiring green completions for hydraulically fractured wells, and emission requirements for certain midstream equipment. Also, in June 2016, the EPA finalized rules which 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. 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

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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.

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 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 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 or administrative orders 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 or limit our growth and revenues, which in turn could affect the amount of cash we have available for distribution. We cannot provide any 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, 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. For example, in June 2015, the U.S. Environmental Protection Agency (EPA) and the Corps, issued a final rule under the CWA, defining the scope of the EPA’s and the Corps’ jurisdiction over waters of the United States (WOTUS). Several legal challenges to the rule followed, along with attempts to roll back the regulation following the change in presidential administration. Currently, the WOTUS rule is active in 22 states and enjoined in 28 states. However, on December 11, 2018, the EPA and the Corps proposed changes to regulations under the CWA that would provide discrete categories of jurisdictional waters and tests for determining whether a particular waterbody meets any of those classifications. Several groups have already announced their intentions to challenge the proposed rule. Therefore, the scope of jurisdiction under CWA is uncertain at this time. To the extent a 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. Such potential regulations or litigation could increase our operating costs, reduce our liquidity, delay or halt our operations or otherwise alter the way we conduct our business, which could in turn have a material adverse effect on our business, financial condition and results of operations. See Items 1. and 2. Business and Properties – Regulations.

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 CAA that, among other things, establish 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 rule makings 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 monitoring and reporting of GHG emissions from specified onshore crude oil and natural gas production sources in the U.S. on an annual basis.

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Climate and related energy policy, laws and regulations could change quickly, and substantial uncertainty exists about the nature of many potential developments that could impact the sources and uses of energy. In December 2015, the United States and 194 other participating countries adopted the Paris Agreement, which calls for each participating country to establish their own nationally determined standards for reducing carbon output. However, in August 2017 the United States notified the United Nations that it would be withdrawing from the Paris Agreement. Also, the EPA had previously finalized standards in June 2016 designed to reduce methane emissions from certain oil and gas facilities. Following the change in administration, there have been attempts to modify these regulations, and litigation is ongoing. As a result, future implementation of these standards is uncertain at this time. Many states also are pursuing climate requirements either directly or indirectly through such measures as alternative fuel mandates. For example, in February 2014, 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. These measures may reduce the future demand for our products, particularly crude oil.

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. Notwithstanding potential risks related to climate change, the International Energy Agency estimates that oil and gas will continue to represent a major share of global energy use through 2040, and other private sector studies project continued growth in demand for the next two decades.  However, recent activism directed at shifting funding away from companies with energy-related assets could result in limitations or restrictions on certain sources of funding for the energy sector. Moreover, activist shareholders have introduced proposals that may seek to force companies to adopt aggressive emission reduction targets or to shift away from more carbon-intensive activities. While we cannot predict the outcomes of such proposals, they could ultimately make it more difficult for operators to engage in exploration and production activities. Finally, it should be noted that many 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 our operations or our customers' exploration and production operations, which in turn could affect demand for our services. See Items 1. and 2. Business and Properties – Regulations.

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 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, such as the greater sage grouse, 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 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.

Subject to the foregoing, 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

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pro-competitive policies in its regulation of interstate crude oil and natural gas pipelines. However, we cannot assure 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 crude oil interstate pipeline transportation, on the one hand, and crude oil 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 changed circumstances on the pipeline or 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 is determined that some 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 and revenues associated with 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 produced water and the delivery and storage of fresh water, including:

• damage to, loss of availability of and delays in gaining access 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;

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

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

• unexpected business interruptions;

• curtailments of operations due to severe seasonal weather;

• riots, strikes, lockouts or other industrial disturbances;

• fires, ruptures and explosions; and

• 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.

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Our asset inspection, maintenance or repair costs may increase in the future. In addition, there could be service interruptions due to unforeseen events or conditions or increased downtime associated with our pipelines that could have a material adverse effect on our business and results of operations.

Gathering systems, pipelines and facilities are generally long-lived assets, and construction and coating techniques have varied over time. Depending on the condition and results of inspections, some assets will require additional maintenance, which could result in increased expenditures in the future. Any significant increase in these expenditures could adversely affect our results of operations, financial position or cash flows, as well as our ability to make cash distributions to our unitholders. 

We monitor the condition of our assets. As there are many factors that are under our influence and others that are not, it is difficult to predict future maintenance capital expenditures related to inspections and repairs. Additionally, there could be service interruptions associated with these maintenance capital expenditures or other unforeseen events. Similarly, laws and regulations may change which could also lead to increased maintenance capital expenditures. Any increase in these expenditures could adversely affect our results of operations, financial position, or cash flows which in turn could impact our ability to make cash distributions to our unitholders.

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, which may limit or restrict our rights or access to or use of the surface estates. Accommodating these competing rights of the surface owners may adversely affect our operations. In addition, we are 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 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. 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, including Terry R. Gerhart, our Chief Executive Officer, John F. Bookout, IV, our Chief Financial Officer, Thomas W. Christensen, our Chief Accounting Officer, John C. Nicholson, our Chief Operating Officer, and Harry R. Beaudry, our General Counsel and Secretary 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 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;

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• 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 have exposure to increases in interest rates. As of December 31, 2018, $60 million and $500 million were outstanding under our revolving credit facility and term loan credit facility, respectively. A 1.0% increase in our interest rates would have resulted in an estimated $5.0 million increase in interest expense for the year ended December 31, 2018. As a result, our results of operations, cash flows and financial condition and, as a further result, our ability to make cash distributions to our unitholders, could be 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 future attacks than other targets in the United States. Our insurance may not protect us against such occurrences. Consequently, it is possible that any of these occurrences, or a combination of them, could have a material adverse effect on our business, financial condition and results of operations.

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

The oil and gas industry has become increasingly dependent on digital technologies to conduct day-to-day operations including certain midstream activities. For example, software programs are used to manage gathering and transportation systems and for compliance reporting. The use of mobile communication devices has increased rapidly. Industrial control systems such as SCADA (supervisory control and data acquisition) now control large scale processes that can include multiple sites and long distances, such as oil and gas pipelines.

We depend on digital technology, including information systems and related infrastructure as well as cloud applications and services, to process and record financial and operating data and to communicate with our employees and business partners. Our business partners, including vendors, service providers, and financial institutions, are also dependent on digital technology. The technologies needed to conduct midstream activities make certain information the target of theft or misappropriation.

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

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

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

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

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

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

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

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

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

Risks Inherent in an Investment in Us

Our General Partner and its affiliates, including Noble, have conflicts of interest with us and our partnership agreement eliminates their default fiduciary duties to us and our unitholders and replaces them with contractual standards that may allow our General Partner and its affiliates to 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.

Noble directly owns an aggregate 45.4% limited partner interest in us. In addition, Noble owns and controls our General Partner. Although our General Partner has a duty to manage us in a manner that is not adverse to the interests of our partnership, 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 of the Partnership (the Subordinated Units) to convert into Common Units of the Partnership (the 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;

• our partnership agreement permits us to distribute up to $45.0 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;

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• 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, the ROFR and ROFO;

• 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 (except to the extent the ROFR or ROFO pertain to such 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.

We expect to distribute a substantial portion of our cash available for distribution, which could limit our ability to grow and make acquisitions.

We expect to distribute most of our available cash for distribution. 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, our growth may not be as fast as that of businesses that reinvest their cash to expand ongoing operations. To the extent we issue additional partnership interests in connection with any acquisitions or expansion capital expenditures, the 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 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. 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 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 agrees to be bound by our partnership agreement and approves the elimination and replacement of fiduciary duties disclosed above.

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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 not adverse to the 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;

• 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;

• our General Partner and its officers and directors will not be liable for monetary damages or otherwise 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

• 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, other than one where our General Partner is permitted to act in its sole discretion, our partnership agreement provides that any determination by our General Partner must be made in good faith. If an affiliate transaction or the resolution of a conflict of interest is not approved by our common unitholders or the conflicts committee, then it will be presumed that, in making its decision, taking any action or failing to act, 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 the Partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.

Cost reimbursements and fees due to 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 unitholders.

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 and secondment 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 and secondment agreement, we will be required to reimburse Noble for the provision of certain operation services and related management 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. 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 cannot 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

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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. Noble currently owns 45.4% of our total outstanding Common Units and Subordinated Units on an aggregate basis. As a result, our public unitholders do not 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 partnership agreement restricts the voting rights of certain unitholders owning 20% or more of our Common Units.

Unitholders’ voting rights are restricted by a provision of our partnership agreement providing that any person or group 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 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 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;

•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.

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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.

Noble currently holds 2,090,014 Common Units and 15,902,584 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 registration rights. 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 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 and rights of first offer contained in our omnibus agreement.

None of our partnership agreement, our omnibus agreement, our commercial agreements or any other agreement in effect 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 except with respect to dedications contained in our commercial agreements and rights of first refusal and rights of first offer contained in our omnibus agreement. 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 call right that may require our unitholders to sell their 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, our unitholders may be required to sell their Common Units at an undesirable time or price and may not receive any return on their investment. Our unitholders may also incur a tax liability upon a sale of their units. Our General Partner and its affiliates currently own approximately 8.8% of our common units (excluding any Common Units owned by the directors 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, assuming no additional issuances of Common Units by us (other than upon the conversion of the Subordinated Units), our General Partner and its affiliates will own approximately 45.4% of our outstanding Common Units.

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 our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Liabilities to partners on account of their partnership interest and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.

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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 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.

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 FERC 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.

Our partnership agreement designates 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 limits 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 provides 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.

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If any person brings any of the aforementioned claims, suits, actions or proceedings (including any claims, suits, actions or proceedings arising out of this offering) 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 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.

The NYSE does not require a publicly traded limited partnership like us to comply with certain of its corporate governance requirements.

Our Common Units are listed on the NYSE. Because we are 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.

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 required to comply with the SEC’s rules implementing Sections 302 and 404 of the Sarbanes-Oxley Act of 2002, which requires 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.

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

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

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 assets consist of direct and indirect ownership interests in our DevCos as well as ownership interests in other midstream ventures. If a sufficient amount of our assets, such as our ownership interests in other midstream ventures, now owned or in the future acquired, are deemed to be “investment securities” within the meaning of the Investment Company Act of 1940, or the Investment Company Act, we would either have to register as an investment company under the Investment Company Act, obtain exemptive relief from the SEC or modify our organizational structure or our contract rights to fall outside the definition of an investment company. 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 our unitholders would generally be taxed again as corporate distributions and none of our income, gains, losses or deductions would flow through to our unitholders. Because a tax would be imposed upon us as a corporation, our cash available for distribution to unitholders 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.

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

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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

Our tax treatment depends on our status as a partnership for U.S. federal income tax purposes. If the Internal Revenue Service (IRS) were to treat us as a corporation for U.S. 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 U.S. federal income tax purposes.

Despite the fact that we are organized as a limited partnership under Delaware law, we would be treated as a corporation for U.S. federal income tax purposes unless we satisfy a “qualifying income” requirement. Based upon our current operations and current Treasury Regulations, we believe that we satisfy the qualifying income requirement. Failing to meet the qualifying income requirement or a change in current law could cause us to be treated as a corporation for U.S. federal income tax purposes or otherwise subject us to taxation as an entity.

If we were treated as a corporation for U.S. federal income tax purposes, we would pay U.S. federal income tax on our taxable income at the corporate tax rate and we would also likely pay additional state and local income taxes at varying rates. Distributions to our unitholders would generally be taxed again as corporate dividends (to the extent of our current and accumulated earnings and profits), and no income, gains, losses, deductions, or credits would flow through to our unitholders. Because a tax would be imposed upon us as a corporation, our distributable cash flow would be substantially reduced.

At the state level, several states have been evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of a material amount of any of these taxes in the jurisdictions in which we own assets or conduct business could substantially reduce the cash available for distribution to our unitholders.

If we were treated as a corporation for U.S. 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 or interpretation on us.

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

The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our Common Units may be modified by administrative, legislative or judicial interpretation at any time. From time to time, members of Congress have proposed and considered substantive changes to the existing U.S. federal income tax laws that would affect publicly traded partnerships, including elimination of partnership tax treatment for publicly traded partnerships.

In addition, the Treasury Department has issued, and in the future may issue, regulations interpreting those laws that affect

publicly traded partnerships. Although there are no current legislative or administrative proposals, there can be no assurance that there will not be further changes to U.S. federal income tax laws or the Treasury Department’s interpretation of the

qualifying income rules in a manner that could impact our ability to qualify as a partnership in the future. We believe the

income that we treat as qualifying satisfies the requirements under current regulations.

We are unable to predict whether any changes or proposals will ultimately be enacted. Any modification to the U.S. 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 U.S. federal income tax purposes and could negatively impact the value of an investment in our Common Units.

You are urged to consult with your own tax advisor with respect to the status of regulatory or administrative developments and proposals and their potential effect on your investment in our Common Units.

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If the IRS contests the U.S. federal income tax positions we take, the market for our Common Units may be adversely impacted and our cash available to our unitholders might be substantially reduced.

The IRS may adopt positions that differ from the conclusions of our counsel expressed in this Annual Report 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 materially and adversely impact on the market for our Common Units and the price at which they trade. In addition, our costs of any contest between us and the IRS will be borne indirectly by our unitholders because the costs will reduce our distributable cash flow.

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

Legislation applicable to partnership tax years beginning after 2017 alters the procedures for auditing large partnerships and for assessing and collecting taxes due (including penalties and interest) as a result of a partnership-level federal income tax audit. If the IRS makes an audit adjustment to our partnership tax return, to the extent possible under the new rules our General Partner may elect to either pay the taxes (including any applicable penalties and interest) directly to the IRS in the year in which the audit is completed or, if we are eligible, issue a revised information statement to each unitholder and former unitholder with respect to an audited and adjusted partnership tax return. Although our General Partner may elect to have our unitholders and former unitholders take such audit adjustment into account and pay any resulting taxes (including applicable penalties or interest) in accordance with their interests in us during the tax year under audit, there can be no assurance that such election will be practical, permissible or effective in all circumstances. If we make payments of taxes and any penalties and interest directly to the IRS in the year in which the audit is completed, cash available for distribution to our unitholders might be substantially reduced, in which case our current unitholders may bear some or all of the tax liability resulting from such audit adjustment, even if the current unitholders did not own Common Units in us during the tax year under audit.

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

Each unitholder is treated as a partner to whom we will allocate taxable income even if the unitholder does not receive any cash distributions from us. Unitholders are required to pay federal income taxes and, in some cases, state and local income taxes, on their share of our taxable income, whether or not they receive cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax due from them with respect to that income.

Tax gain or loss on 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 U.S. 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 Common Units, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. Thus, a unitholder may recognize both ordinary income and capital loss from the sale of Common Units if the amount realized on a sale of the Common Units is less than the unitholder’s adjusted basis in Common Units. In addition, because the amount realized includes a unitholder’s share of our non-recourse liabilities, a unitholder that sells Common Units may incur a tax liability in excess of the amount of cash received from the sale.

Unitholders may be subject to limitations on their ability to deduct interest expense we incur.

Our ability to deduct business interest expense will be limited for U.S. federal income tax purposes to an amount equal to our business interest income and 30% of our “adjusted taxable income” during the taxable year computed without regard to any business interest income or expense, and in the case of taxable years beginning before 2022, any deduction allowable for depreciation, amortization, or depletion. Business interest expense that we are not entitled to fully deduct will be allocated to each unitholder as excess business interest and can be carried forward by the unitholder to successive taxable years and used to offset any excess taxable income allocated by us to the unitholder. Any excess business interest expense allocated to a unitholder will reduce the unitholder’s tax basis in its partnership interest in the year of the allocation even if the expense does not give rise to a deduction to the unitholder in that year.

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Tax-exempt entities 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 (IRAs), raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from U.S. federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. With respect to taxable years beginning after December 31, 2017, subject to the proposed aggregation rules for certain similarly situated businesses or activities issued by the Treasury Department, a tax-exempt entity with more than one unrelated trade or business cannot aggregate losses from one unrelated trade or business to offset income from another to reduce total unrelated business taxable income. As a result, for the years beginning after December 31, 2017, it may not be possible for tax-exempt entities to utilize losses from an investment in us to offset unrelated business taxable income from another unrelated trade or business and vice versa. Tax exempt entities should consult a tax advisor before investing in our Common Units.

Non-U.S. unitholders will be subject to U.S. federal income taxes and withholding with respect to income and gain from owning our Common Units.

Non-U.S. unitholders are generally taxed and subject to U.S. federal income tax filing requirements on income effectively connected with a U.S. trade or business. Income allocated to our unitholders and, under recently enacted legislation, any gain from the sale of our Common Units will generally be considered to be “effectively connected” with a U.S. trade or business. As a result, distributions to a non-U.S. unitholder will be subject to withholding at the highest applicable effective tax rate, and a non-U.S. unitholder who sells or otherwise disposes of a common unit will also be subject to U.S. federal income on the gain realized from the sale or disposition of that Common Unit.

Recently enacted legislation also imposes a U.S. federal income tax withholding obligation of 10% of the amount realized upon a non-U.S. unitholder’s sale or exchange of an interest in a partnership that is engaged in a U.S. trade or business. However, due to challenges of administering a withholding obligation applicable to open market trading and other complications, the application of this withholding rule to dispositions of publicly traded partnership interests has been temporarily suspended by the IRS until regulations or other guidance that resolves the challenges have been issued. It is not clear if or when such regulations or guidance will be issued. Non-U.S. persons should consult a tax advisor before investing in our Common Units.

We 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, our depreciation and amortization positions 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 unitholders. It also could affect the timing of these tax benefits or the amount of gain from a unitholder’s sale of Common Units and could have a negative impact on the value of our Common Units or result in tax return audit adjustments.

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

We generally prorate our items of income, gain, loss and deduction for U.S. federal income tax purposes between transferors and transferees of our Common Units each month based upon the ownership of our Common Units on the first day of each month, instead of on the basis of the date a particular unit is transferred. Although Treasury Regulations allow publicly traded partnerships to use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders, these Treasury Regulations do not specifically authorize all aspects of our proration method. If the IRS were to successfully challenge our proration method, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

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, the unitholder would no longer be treated for U.S. 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 there are no specific rules governing the U.S. federal income tax consequence of loaning a partnership interest, 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, the unitholder may no longer be treated for U.S. 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

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the unitholder as to those Common Units could be fully taxable as ordinary income. 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.

We have adopted 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 U.S. federal income tax purposes.

A successful IRS challenge to these methods or allocations could adversely affect the amount, character and timing of our taxable income or loss and a unitholder’s distributive share of these items. 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 items of income, gain, loss and deduction and a unitholder’s distributive share of these items without the benefit of additional deductions.

As a result of investing in our Common Units, our unitholders 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 U.S. 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 our unitholders’ responsibility to file all federal, state and local tax returns and pay any taxes due in these jurisdictions. Unitholders should consult with their own tax advisors regarding the filing of such tax returns, the payment of such taxes, and the deductibility of any taxes paid.

Item 1B.  Unresolved Staff Comments

None.

Item 3.  Legal Proceedings

We may become involved in various legal proceedings in the ordinary course of business. These proceedings would be subject to the uncertainties inherent in any litigation, and we will regularly assess the need for accounting recognition or disclosure of these contingencies. We will defend ourselves vigorously in all such matters.

Information regarding legal proceedings is set forth in Item 8. Financial Statements and Supplementary Data – Note 15. Commitments and Contingencies of this Form 10-K, which is incorporated by reference into this Part I, Item 3.

Information regarding environmental proceedings is set forth in Items 1. and 2. Business and Properties – Regulations – Environmental Matters – Water – Colorado Water Quality Control Act of this Form 10-K, which is incorporated by reference into this Part I, Item 3.

Item 4.  Mine Safety Disclosures

Not Applicable.

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PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Our Common Units are listed on the NYSE and traded under the symbol “NBLX.” As of December 31, 2018, our units were held by 10 holders of record. The number of holders does not include the holders for whom units are held in a “nominee” or “street” name. In addition, as of December 31, 2018, Noble owned 2,090,014 of our Common Units and 15,902,584 of our Subordinated Units, which together represent a 45.4% limited partner interest in us.

Securities Authorized for Issuance Under Equity Compensation Plans 

In connection with the completion of the IPO, the board of directors of our General Partner adopted the Noble Midstream Partners LP 2016 Long-Term Incentive Plan (the LTIP), which permits the issuance of up to 1,860,000 Common Units. See Item 8. Financial Statements and Supplementary Data – Note 11. Unit-Based Compensation for information regarding our equity compensation plan as of December 31, 2018.

The following table summarizes information regarding the number of Common Units that are available for issuance under our LTIP as of December 31, 2018.

Plan Category	Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Rights	Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights	Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in Column (a))
	(a)	(b)	(c)
Equity Compensation Plans Approved by Security Holders	—	—	1,763,411
Equity Compensation Plans Not Approved by Security Holders	—	—	—
Total	—	—	1,763,411

Distributions of Available Cash

General

Our partnership agreement requires that, within 45 days after the end of each quarter we distribute all of our available cash to unitholders of record on the applicable record date.

On January 24, 2019, the board of directors of our General Partner declared a quarterly cash distribution of $0.5858 per limited partner unit. The distribution was paid on February 11, 2019, to unitholders of record on February 4, 2019. Also on February 11, 2019, a cash distribution of $2.4 million was paid to Noble related to its Incentive Distribution Rights (IDRs), based upon the level of distribution paid per Common and Subordinated Unit.

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 for anticipated future credit needs);

• 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.

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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.

Intent to Distribute the Minimum Quarterly Distribution

Under our current cash distribution policy, we intend distribute at least the minimum quarterly distribution of $0.375 per unit, or $1.50 per unit on an annualized basis, to the holders of our Common and Subordinated Units 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. We expect that if we are successful in executing our business strategy, we will grow our business in a steady and sustainable manner and distribute to our unitholders a portion of any increase in our cash available for distribution resulting from such growth. We expect our General Partner may cause us to establish reserves for specific purposes, such as major capital expenditures or debt service payments, or may choose to generally reserve cash in the form of excess distribution coverage from time to time for the purpose of maintaining stability or growth in our quarterly distributions. In addition, our General Partner may cause us to borrow amounts to fund distributions in quarters when we generate less cash than is necessary to sustain or grow our cash distributions per unit. Our cash distribution policy reflects a judgment that our unitholders will be better served by our distributing rather than retaining our cash available for distribution. However, there is no guarantee that we will pay the minimum quarterly distribution or any other amount of distributions 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.

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 IDRs that entitle it to receive increasing percentages, up to a maximum of 50%, of the available cash we distribute from operating surplus in excess of $0.4313 per unit per quarter. The maximum distribution of 50% does not include any distributions that Noble may receive on Common Units or Subordinated Units that it owns.

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 IDRs, 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.” The percentage interests shown for our unitholders and 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 IDRs and that there are no arrearages on Common Units.

		Marginal Percentage Interest in Distributions
	Total Quarterly Distribution Per Unit	Unitholders		IDR Holders
Minimum Quarterly Distribution	$0.3750	100	%	—	%
First Target Distribution	above $0.3750 up to $0.4313	100	%	—	%
Second Target Distribution	above $0.4313 up to $0.4688	85	%	15	%
Third Target Distribution	above $0.4688 up to $0.5625	75	%	25	%
Thereafter	above $0.5625	50	%	50	%

Subordinated Units and Subordination Period

Our partnership agreement provides that, during the subordination period, the Common Units have the right to receive distributions of available cash from operating surplus each quarter in an amount equal to the minimum quarterly distribution, plus any arrearages in the payment of the minimum quarterly distribution on the Common Units from prior quarters, before any distributions of available cash from operating surplus may be made on the Subordinated Units. No arrearages will accrue or be payable on the Subordinated Units.

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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.

Subordinated Units

Noble owns 15,902,584 Subordinated Units, which represents all of our Subordinated Units.

Definition of Subordination Period

The subordination period will end on the first business day following the distribution of available cash in respect of any quarter beginning after September 30, 2019 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 $1.50 (the annualized minimum quarterly distribution), for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date;

• the adjusted operating surplus generated during each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of $1.50 (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 September 30, 2017, 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 $2.25 (150% of the annualized minimum quarterly distribution), for the four-quarter period immediately preceding that date;

• the adjusted operating surplus generated during the four-quarter period immediately preceding that date equaled or exceeded the sum of (i) $2.25 (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.

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Item 6. Selected Financial Data

Selected Financial Data for periods prior to September 20, 2016 represent the Contributed Businesses of certain of Noble’s midstream assets as the accounting Predecessor to the Partnership, presented on a carve-out basis of Noble’s historical ownership of the Predecessor. The Predecessor financial data has been prepared from the separate records maintained by Noble and may not necessarily be indicative of the actual results of operations that might have occurred if the Predecessor had been operated separately during the periods reported. The information presented below should be read in conjunction with the information in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and the consolidated financial statements and related notes appearing in Item 8. Financial Statements and Supplementary Data.

	Year Ended December 31,
(thousands, except as noted)	2018			2017			2016			2015			2014
Statements of Operations
Total Revenues	$	495,520		$	239,281		$	160,724		$	87,837		$	2,086
Net Income	188,876			163,636			85,502			38,042			(15,091		)
Net Income Attributable to Noble Midstream Partners LP	162,734			140,572			28,458			N/A			N/A
Net Income Attributable to Limited Partners Per Limited Partner Common and Subordinated Unit
Basic	$	3.96		$	4.10		$	0.89		N/A			N/A
Diluted	3.96			4.10			0.89			N/A			N/A
Cash Distributions Declared per Limited Partner Unit	2.1913			1.8113			0.4333			N/A			N/A
Balance Sheet
Cash and Cash Equivalents	$	10,740		$	18,026		$	57,421		$	26,612		$	—
Total Property, Plant and Equipment, Net	1,421,252			661,768			279,403			250,933			195,513
Intangible Assets, Net	310,202			—			—			—			—
Goodwill	109,734			—			—			—			—
Total Assets	1,997,917			829,758			369,359			305,318			216,512
Long-Term Debt	559,021			85,000			—			—			—
Total Liabilities	681,684			213,528			26,454			41,779			2,839
Total Equity	1,316,233			616,230			342,905			263,539			213,673
Cash Flows
Net Cash Provided by (Used in) Operating Activities	$	239,797		$	166,228		$	118,451		$	69,394		$	(12,534	)
Net Cash Used in Investing Activities	(1,265,354		)	(362,195		)	(38,137		)	(54,461		)	(79,904		)
Net Cash Provided by (Used in) Financing Activities	981,717			194,077			(49,505		)	11,679			92,438
Non-GAAP Financial Measures(1)
Adjusted EBITDA	$	274,896		$	179,002		$	126,271		$	72,754		$	(9,388	)
Adjusted EBITDA Attributable to Noble Midstream Partners LP	221,444			154,509			30,697			N/A			N/A
Distributable Cash Flow of Noble Midstream Partners LP	184,685			137,935			28,425			N/A			N/A
Throughput and Crude Oil Sales Volumes
Crude Oil Sales Volumes (Bbl/d)	6,129			—			—			—			—
Crude Oil Gathering Volumes (Bbl/d)	171,330			65,655			45,236			33,977			16,522
Natural Gas Gathering Volumes (MMBtu/d)	310,087			180,918			132,147			86,103			71,137
Crude Oil and Natural Gas Gathering Volumes (Boe/d)	217,214			88,850			62,178			45,016			25,642
Produced Water Gathering Volumes (Bbl/d)	101,200			24,431			10,592			5,198			5,422
Fresh Water Services Volumes (Bbl/d)	175,754			155,990			94,227			51,980			43,797

⁽¹⁾  Adjusted EBITDA and Distributable Cash Flow are not defined in GAAP and should not be considered an alternative to, or more meaningful than, net income, net cash provided by operating activities or any other measure as reported in accordance with GAAP. For definitions and reconciliations of Adjusted EBITDA and Distributable Cash Flow to their most directly comparable financial measures calculated and presented in accordance with GAAP, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations.

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) is intended to provide a narrative about our business from the perspective of our management. Our MD&A is presented in the following major sections:

• Executive Overview;

• Operating Outlook;

• Results of Operations;

• Liquidity and Capital Resources; and

• Critical Accounting Policies and Estimates.

Predecessor  This Annual Report includes the assets, liabilities and results of operations of the Contributed Businesses on a carve-out basis (our Predecessor for accounting purposes) for periods prior to September 20, 2016, the date on which we completed the IPO. Our future results of operations may not be comparable to our Predecessor’s historical results of operations.

MD&A is the Partnership’s analysis of its financial performance and of significant trends that may affect future performance. It should be read in conjunction with the consolidated financial statements and related notes appearing elsewhere in this report. It contains forward-looking statements including, without limitation, statements relating to the Partnership’s plans, strategies, objectives, expectations and intentions. The words “anticipate,” “estimate,” “believe,” “budget,” “continue,” “could,” “intend,” “may,” “plan,” “potential,” “predict,” “seek,” “should,” “will,” “would,” “expect,” “objective,” “projection,” “forecast,” “goal,” “guidance,” “outlook,” “effort,” “target”, “on schedule”, “strategy” and similar expressions identify forward-looking statements. The Partnership does not undertake to update, revise or correct any of the forward-looking information unless required to do so under the federal securities laws. Readers are cautioned that such forward-looking statements should be read in conjunction with the Partnership’s disclosures under “Disclosure Regarding Forward-Looking Statements” in this Form 10-K.

EXECUTIVE OVERVIEW

Overview

We are a growth-oriented Delaware master limited partnership formed in December 2014 by our Parent, Noble, to own, operate, develop and acquire a wide range of domestic midstream infrastructure assets. Our current areas of focus are in the DJ Basin in Colorado and the Delaware Basin in Texas. We currently provide crude oil, natural gas, and water-related midstream services through long-term, fixed-fee contracts, as well as purchase crude oil from producers and sell crude oil to customers at various delivery points on our gathering systems. Our business activities are conducted through three reportable segments: Gathering Systems (primarily includes crude oil, natural gas and produced water gathering and crude oil sales), Fresh Water Delivery, and Investments and Other. We often refer to the services of our Gathering Systems and Fresh Water Delivery reportable segments collectively as our midstream services.

We are Noble’s primary vehicle for its midstream operations in the onshore United States. We believe that our diverse midstream infrastructure assets and our relationship with Noble position us as a leading midstream service provider.

Significant Results

The following discussion highlights significant operating, transactional and financial results for the year ended December 31, 2018.

Significant Operational Highlights Include:

• average crude oil sales volumes of 6.1 MBbl/d;

• average crude oil gathering volumes of 171.3 MBbl/d;

• average natural gas gathering volumes of 310.1 BBtu/d;

• average produced water gathering volumes of 101.2 MBbl/d;

• average fresh water delivery volumes of 175.8 MBbl/d;

• completion of the Coronado, Collier and Billy Miner Train II CGFs in the Delaware Basin;

• commencement of gathering services for Noble in the Mustang IDP area; and

• commencement of gathering services for a third party producer in the Delaware Basin.

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Significant Transactional Highlights Include:

• closing of the Black Diamond Acquisition on January 31, 2018;

• extending the maturity date of our revolving credit facility to March 2023 and increasing the facility size to $800 million with the ability to increase the borrowing capacity by an additional $350 million; and

• entering into the term loan credit facility that permitted aggregate borrowing up to $500 million.

Significant Financial Highlights Include:

• net income of $188.9 million, of which $162.7 million is attributable to the Partnership;

• declared and paid a cash distribution per unit each quarter during 2018 that represented a 20% increase over the prior year quarter distribution per unit;

• declared and paid a cash distribution per unit each quarter during 2018 that represented a 4.7% increase over the prior quarter distribution per unit;

• net cash provided by operating activities of $239.8 million;

• Adjusted EBITDA (non-GAAP financial measure) of $274.9 million, of which $221.4 million is attributable to the Partnership; and

• distributable cash flow (non-GAAP financial measure) of $184.7 million.

For additional information regarding our non-GAAP financial measures, see Adjusted EBITDA (Non-GAAP Financial Measure), Distributable Cash Flow (Non-GAAP Financial Measure) and Reconciliation of Non-GAAP Financial Measures, below.

OPERATING OUTLOOK

2019 Capital Investment Program

Our preliminary 2019 capital investment program, excluding acquisition capital, will accommodate a gross investment level of approximately $335 to $375 million, with $180 to $210 million attributable to the Partnership. We will evaluate the level of capital spending throughout the year based on the following factors, among others, and their effect on project financial returns: 

• pace of our customers’ development;

• operating and construction costs and our ability to achieve material supplier price reductions;

• impact of new laws and regulations on our business practices;

• indebtedness levels; and

• availability of financing or other sources of funding.

We plan to fund our capital investment program with cash on hand, from cash generated from operations, borrowings under our revolving credit facility and, if necessary, the issuance of additional equity or debt securities.

Colorado Proposition #112

On November 6, 2018, a majority of Colorado voters voted against Proposition #112, which, if passed, would have significantly limited, or in some cases prevented, the future development of crude oil and natural gas in areas where we provide midstream services. Initiatives have been underway in the State of Colorado to regulate, limit or ban hydraulic fracturing or other facets of crude oil and natural gas exploration, development or operations for some time. We are monitoring the work of the State of Colorado General Assembly to create a framework for future oil and gas development in the State.

Impact of Tariffs

During 2018, the U.S. Administration imposed import tariffs of 25% on steel products and 10% on aluminum products, as well as quantitative restrictions on imports of steel and/or aluminum products from various countries. More recently in August 2018, the US Administration permitted relief from these quotas including relief on steel quotas from Argentina, Brazil, and South Korea and on aluminum from Argentina.

The U.S. oil and gas industry relies on steel for drilling and completion of new wells as well as constructing pipelines and gathering facilities. Much of the steel required is in the form of specialty steel products, manufactured to exact specifications, and may not be available domestically in sufficient quantities. Implementation of these tariffs will likely increase prices for specialty and other products used in various aspects of upstream, midstream and downstream activities. Furthermore, the tariffs and quantitative restrictions may cause disruption in the energy industry’s supply chain, resulting in delay or cessation of drilling efforts or postponement or cancellation of new inter- or intra-state pipeline projects that the industry is relying on to transport its increasing onshore production to market, as well as endangering US liquefied natural gas (LNG) export projects resulting in negative impacts on natural gas production. 

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Revenue Agreement Amendments with Noble

On August 2, 2018, Green River DevCo LP and Noble entered into amendments (the Amendments) to our crude oil and natural gas gathering revenue agreements as well as our produced water and fresh water services revenue agreements in the Mustang IDP.

The crude oil gathering and produced water services amendments established fees for services in the Mustang IDP which had not previously been provided for in the agreements. The natural gas gathering amendment provides for a revised fee to reflect a gathering system that gathers product meeting pipeline specifications rather than a CGF as originally contemplated. The fresh water services amendment also provides for a revised fee to reflect higher per-well water usage associated with enhanced completions. The Amendments are effective as of July 1, 2018.

In exchange for entering into the Amendments, Noble agreed to grant us:

• a three-year minimum volume commitment for freshwater deliveries in the Wells Ranch IDP , which will commence in 2019 and provides for deliveries of 50,000 Bbl/d in year one and increases to 60,000 Bbl/d in year two;

• an incremental 10-year dedication for crude oil transportation from the Wells Ranch CGF to the Platteville crude oil treating facility that will commence upon the expiration of an existing third-party contract at the end of 2020; and

• the assignment of its option with EPIC to acquire a 15% equity interest in the EPIC Y-Grade Pipeline.

EPIC Equity Interests

On August 2, 2018, Noble assigned its option with EPIC to acquire a 15% equity interest in the EPIC Y-Grade Pipeline to the Partnership. On January 31, 2019, Noble assigned its option to acquire a 30% equity interest in the EPIC Crude Oil Pipeline to the Partnership. Both options were set to expire February 1, 2019.

On January 31, 2019, the Partnership exercised and closed its option with EPIC to acquire the equity interest in the EPIC Y-Grade Pipeline. At closing, we made capital contributions of approximately $103 million. Our total cash contributions are expected to be approximately $165 million to $180 million for the EPIC Y-Grade Pipeline, with substantially all of the cash contributions in 2019. We intend to fund our cash contributions for the EPIC Y-Grade Pipeline with our revolving credit facility. The EPIC Y-Grade Pipeline is an approximately 700-mile pipeline linking NGL reserves in the Permian Basin and Eagle Ford Shale to Gulf Coast refiners, petrochemical companies, and export markets. The pipeline will have a throughput capacity of approximately 440 MBbl/d with multiple origin points.

Also on January 31, 2019, the Partnership exercised its option to acquire the equity interest in the EPIC Crude Oil Pipeline. Closing of the Partnership’s equity interest in the EPIC Crude Oil Pipeline is expected to occur later in first quarter 2019, subject to certain conditions precedent. Our total cash contributions are expected to be approximately $330 million to $350 million for the EPIC Crude Pipeline, with substantially all of the cash contributions in 2019. We intend to fund our cash contributions for the EPIC Crude Pipeline with our revolving credit facility and other sources of funding. The planned EPIC Crude Oil Pipeline will be a 30-inch pipeline with a capacity of 590 MBbl/d from the Delaware Basin to the Gulf Coast.

Delaware Crossing Joint Venture

On October 2, 2018, we entered into a non-binding letter of intent with Salt Creek to form the Delaware Crossing Joint Venture to construct a crude oil pipeline system with a capacity of 160 MBbl/d in the Delaware Basin. On February 7, 2019, we executed definitive agreements and completed the formation of the Delaware Crossing Joint Venture. As Salt Creek has commenced construction of the pipeline prior to formation, we made capital contributions of approximately $38 million at closing.

The 95-mile pipeline system will originate in Pecos County, Texas, with additional connections in Reeves County and Winkler County, Texas. The project footprint will be served by a combination of in-field crude oil gathering lines and a trunkline to a hub in Wink, Texas. The project is underpinned by approximately 192,000 dedicated gross acres and nearly 100 miles of pipeline in Pecos, Reeves, Ward and Winkler Counties, Texas. The pipeline is expected to be operational in the third quarter of 2019.

Development Project Updates

Laramie River DevCo LP We completed the integration of the assets acquired in the Black Diamond Acquisition and transitioned operation of the system to us. Subsequent to the integration, we completed the connection of the system to a major crude oil takeaway outlet in the DJ Basin. The system now connects to all four major crude oil takeaway outlets in the DJ Basin.

We secured additional long-term dedications for the Black Diamond system, representing more than 200 future wells across approximately 17,000 incremental acres. The additional dedications come from an existing third party customer on the system as well as a new third-party customer and increased total acreage dedicated to the Black Diamond system by 12% to approximately 158,000 acres.

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Blanco River DevCo LP We completed and brought online the Coronado, Collier and Billy Miner Train II CGFs. We now have five CGFs online in the Delaware Basin. We connected 67 wells to our gathering systems. Additionally, we commenced gathering services on an initial well for a third party Delaware Basin producer in September 2018. The third party customer development plan spans across approximately 13,000 dedicated acres in Reeves County, Texas, with additional activity on the acreage anticipated in 2019.

Green River DevCo LP In March 2018, we recommenced our fresh water delivery services for Noble. During second quarter 2018, we completed the crude oil, natural gas and produced water gathering system in the Mustang IDP and commenced gathering services. We connected 30 wells to the Mustang IDP gathering system.

Trinity River DevCo LLC We expanded the capacity of the Advantage pipeline to 200 MBbl/d from 150 MBbl/d. We reached a long-term agreement for the Advantage pipeline system to service a major producing company’s facilities on such customer’s Southern Delaware Basin position totaling approximately 20,000 net acres and began services in November 2018.

How We Evaluate Our Operations

Our management uses a variety of financial and operating metrics, each as described in more detail below, to analyze our performance. These metrics are significant factors in assessing our operating results and profitability and include:

• throughput volumes (Gathering Systems and Fresh Water Delivery reportable segments);

• operating costs and expenses;

• Adjusted EBITDA (non-GAAP financial measure);

• distributable cash flow (non-GAAP financial measure); and

• capital expenditures.

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RESULTS OF OPERATIONS

Results of operations were as follows:

	Year Ended December 31,
(thousands)	2018			2017			2016
Revenues
Midstream Services — Affiliate	$	281,162		$	224,401		$	160,724
Midstream Services — Third Party	72,868			14,880			—
Crude Oil Sales — Third Party	141,490			—			—
Total Revenues	495,520			239,281			160,724
Costs and Expenses
Cost of Crude Oil Sales	136,368			—			—
Direct Operating	84,482			54,007			29,107
Depreciation and Amortization	65,314			12,953			9,066
General and Administrative	24,250			13,396			9,914
Other Operating Expense	1,806			—			—
Total Operating Expenses	312,220			80,356			48,087
Operating Income	183,300			158,925			112,637
Other (Income) Expense
Interest Expense, Net of Amount Capitalized	10,492			1,603			3,373
Investment Income	(16,289		)	(6,334		)	(4,526		)
Total Other (Income) Expense	(5,797		)	(4,731		)	(1,153		)
Income Before Income Taxes	189,097			163,656			113,790
Income Tax Provision	221			20			28,288
Net Income	188,876			163,636			$	85,502
Less: Net Income Prior to the IPO on September 20, 2016	—			—			45,990
Net Income Subsequent to the IPO on September 20, 2016	188,876			163,636			39,512
Less: Net Income Attributable to Noncontrolling Interests	26,142			23,064			11,054
Net Income Attributable to Noble Midstream Partners LP	$	162,734		$	140,572		$	28,458
Adjusted EBITDA(1) Attributable to Noble Midstream Partners LP	$	221,444		$	154,509		$	30,697
Distributable Cash Flow(1) of Noble Midstream Partners LP	$	184,685		$	137,935		$	28,425

⁽¹⁾  Adjusted EBITDA and Distributable Cash Flow are not defined in GAAP and should not be considered an alternative to, or more meaningful than, net income, net cash provided by operating activities or any other measure as reported in accordance with GAAP. For additional information regarding our non-GAAP financial measures, please see — Adjusted EBITDA (Non-GAAP Financial Measure), Distributable Cash Flow (Non-GAAP Financial Measure) and Reconciliation of Non-GAAP Financial Measures, below.

Throughput and Crude Oil Sales 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 as well as the crude oil volumes we sell to customers. These volumes are affected primarily by the level of drilling and completion activity by our customers in our areas of operations, and 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.

Our customers’ willingness to engage in drilling and completion activity is determined by a number of factors, the most important of which are the prevailing and projected prices of crude oil and natural gas, the cost to drill 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.

Our customers have dedicated acreage to us based on the services we provide. Our commercial agreements with Noble provide that, in addition to our existing dedicated acreage, any future acreage that is acquired by Noble in the 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 and treating.

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Throughput and crude oil sales volumes related to our Gathering Systems reportable segment and throughput volumes related to our Fresh Water Delivery reportable segment were as follows:

	Year Ended December 31,
	2018	2017	2016
Colorado River DevCo LP (Wells Ranch IDP and East Pony IDP) (1)
Crude Oil Gathering Volumes (Bbl/d)	62,255	56,531	45,236
Natural Gas Gathering Volumes (MMBtu/d)	221,942	172,284	132,147
Produced Water Gathering Volumes (Bbl/d)	16,984	14,097	10,592
Fresh Water Delivery Volumes (Bbl/d)	47,012	83,856	64,306
San Juan River DevCo LP (East Pony IDP) (1)
Fresh Water Delivery Volumes (Bbl/d)	—	34,676	22,423
Green River DevCo LP (Mustang IDP) (1)
Crude Oil Gathering Volumes (Bbl/d)	6,519	—	—
Natural Gas Gathering Volumes (MMBtu/d)	12,934	—	—
Produced Water Gathering Volumes (Bbl/d)	4,874	—	—
Fresh Water Delivery Volumes (Bbl/d)	68,312	—	7,498
Blanco River DevCo LP (Delaware Basin) (1)
Crude Oil Gathering Volumes (Bbl/d)	28,235	3,791	—
Natural Gas Gathering Volumes (MMBtu/d)	74,120	8,634	—
Produced Water Gathering Volumes (Bbl/d)	71,297	7,996	—
Laramie River DevCo LP (Greeley Crescent IDP and Black Diamond Dedication Area) (1)
Crude Oil Sales Volumes (Bbl/d)	6,129	—	—
Crude Oil Gathering Volumes (Bbl/d)	74,321	5,333	—
Natural Gas Gathering Volumes (MMBtu/d)	1,091	—	—
Produced Water Gathering Volumes (Bbl/d)	8,045	2,338	—
Fresh Water Delivery Volumes (Bbl/d)	60,430	37,458	—
Total Gathering Systems
Crude Oil Sales Volumes (Bbl/d)	6,129	—	—
Crude Oil Gathering Volumes (Bbl/d)	171,330	65,655	45,236
Natural Gas Gathering Volumes (MMBtu/d)	310,087	180,918	132,147
Barrels of Oil Equivalent (Boe/d)	217,214	88,850	62,178
Produced Water Gathering Volumes (Bbl/d)	101,200	24,431	10,592
Total Fresh Water Delivery
Fresh Water Services Volumes (Bbl/d)	175,754	155,990	94,227

⁽¹⁾  See Item 8. Financial Statements and Supplementary Data – Note 1. Organization and Nature of Operations for DevCo ownership interests.

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Revenues

Revenues from our Gathering System and Fresh Water Delivery reportable segments were as follows:

			Increase (Decrease) from Prior Year				Increase (Decrease) from Prior Year
(in thousands)	2018				2017				2016
Year Ended December 31,
Crude Oil, Natural Gas and Produced Water Gathering — Affiliate	$	207,920	46	%	$	142,864	52	%	$	94,160
Crude Oil, Natural Gas and Produced Water Gathering — Third Party	48,387		1,119	%	3,971		N/M		—
Fresh Water Delivery — Affiliate	69,266		(9	)%	75,860		26	%	60,001
Fresh Water Delivery — Third Party	19,345		77	%	10,909		N/M		—
Crude Oil Sales — Third Party	141,490		N/M		—		N/M		—
Other — Affiliate	3,976		(30	)%	5,677		(13	)%	6,563
Other — Third Party	5,136		N/M		—		N/M		—
Total Midstream Services Revenues	$	495,520	107	%	$	239,281	49	%	$	160,724

N/M amount is not meaningful.

Revenues Trend Analysis

Revenues increased during 2018 as compared with 2017 and increased during 2017 as compared with 2016. The increases in revenues by reportable segment were as follows:

Gathering Systems Gathering Systems revenues increased by $254.4 million during 2018 as compared with 2017 due to the following:

• an increase of $141.5 million in crude oil sales due to the commencement of services upon closing of the Black Diamond Acquisition;

• an increase of $43.1 million in crude oil, natural gas and produced water gathering services revenues driven by an increase in throughput volumes in the Delaware Basin resulting from a full year of gathering services revenues and the commencement of services with a third party customer during 2018;

• an increase of $34.1 million in crude oil and natural gas gathering services revenues due to the commencement of services upon closing of the Black Diamond Acquisition;

• an increase of $19.9 million in crude oil, natural gas and produced water gathering services revenues driven by an increase in throughput volumes in the Wells Ranch IDP and East Pony IDP;

• an increase of $10.3 million in crude oil, natural gas and produced water gathering services revenues due to the commencement of services in the Mustang IDP during 2018;

• an increase of $8.2 million in crude oil and produced water gathering services due to providing a full year of services in the Greeley Crescent IDP to an unaffiliated third party; and

• an increase of $3.5 million in crude oil, natural gas and produced water gathering services revenue driven by rate escalations in the Wells Ranch IDP and East Pony IDP;

partially offset by:

• a decrease of $15.0 million in produced water hauling, recycling and disposal services driven by decreased use of third party services in the Wells Ranch IDP and East Pony IDP.

Gathering Systems revenues increased by $51.8 during 2017 as compared with 2016 due to the following:

• an increase of $24.4 million in crude oil, natural gas and produced water gathering services revenues driven by an increase in throughput volumes in the Wells Ranch IDP and East Pony IDP resulting from expansion and gathering system growth;

• an increase of $14.3 million in produced water hauling, recycling and disposal services driven by increased use of third party services in the Wells Ranch IDP and East Pony IDP;

• an increase of $5.3 million in crude oil, natural gas and produced water gathering services revenues due to the commencement of services in the Delaware Basin during third quarter 2017;

• an increase of $4.1 million in crude oil, natural gas and produced water gathering services revenues driven by rate escalations in the Wells Ranch IDP and East Pony IDP;

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• an increase of $4.0 million in crude oil and produced water gathering services revenues due to the commencement of services in the Greeley Crescent IDP to an unaffiliated third party in 2017.

Fresh Water Delivery Fresh Water Delivery revenues increased by $1.8 million during 2018 as compared with 2017 due to the following:

• an increase of $36.7 million in fresh water delivery revenues due to the recommencement of services in the Mustang IDP during 2018; and

• an increase of $8.4 million in fresh water delivery revenues driven by increased fresh water volumes delivered to a third party customer in the Greeley Crescent IDP;

substantially offset by:

• a decrease of $43.3 million in fresh water delivery revenues due to a decrease in fresh water deliveries in the Wells Ranch IDP and East Pony IDP resulting from reduced well completion activity by Noble.

Fresh Water Delivery revenues increased by $26.8 million during 2017 as compared with 2016 due to the following:

• an increase of $18.5 million in fresh water delivery revenues driven by increased fresh water volumes required per well for higher intensity completions in the Wells Ranch IDP and East Pony IDP;

• an increase of $10.9 million in fresh water delivery revenues due to the commencement of services in the Greeley Crescent IDP to an unaffiliated third party in 2017; and

• an increase of $2.1 million in fresh water delivery revenues driven by rate escalations in the Wells Ranch IDP and East Pony IDP;

partially offset by:

• a decrease of $4.7 million in fresh water delivery revenues due to a decrease in fresh water deliveries in the Mustang IDP resulting from the timing of well completion activity by Noble.

Costs and Expenses

Direct Operating Expense

We seek to maximize the profitability of our operations in part by minimizing, to the extent appropriate, expenses directly associated with operating our assets. Direct labor costs, ad valorem taxes, repair and maintenance costs, integrity management costs, utilities and contract services comprise the most significant portion of our operations and maintenance expense. Many of these expenses remain relatively stable across broad ranges of throughput volumes, but a portion of these expenses can fluctuate from period to period depending on the mix of activities performed during that period and the timing of these expenses. We also seek to manage 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

Noble charges us a combination of direct and allocated charges for general and administrative services. Direct charges include a fixed fee under our omnibus agreement and compensation of our executives under our secondment agreement based on the percentage of time spent working on us. Between January 2015 and the IPO date, Noble charged us a fixed fee for overhead and support services.

We incur incremental general and administrative expenses attributable to being a publicly traded partnership, including expenses associated with: annual, quarterly and current reporting with the SEC; tax return and Schedule K-1 preparation and distribution; Sarbanes-Oxley Act of 2002 compliance; NYSE listing; independent auditor fees; legal fees; investor relations expenses; transfer agent and registrar fees; incremental salary and benefits costs of seconded employees; outside director fees; director and officer insurance coverage expenses; and compensation expense associated with the LTIP.

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Costs and Expenses Trend Analysis

Costs and expenses were as follows:

			Increase from Prior Year				Increase from Prior Year
(in thousands)	2018				2017				2016
Year Ended December 31,
Costs and Expenses
Cost of Crude Oil Sales	$	136,368	N/M		$	—	N/M		$	—
Direct Operating	84,482		56	%	54,007		86	%	29,107
Depreciation and Amortization	65,314		404	%	12,953		43	%	9,066
General and Administrative	24,250		81	%	13,396		35	%	9,914
Other Operating Expense	1,806		N/M		—		N/M		—
Total Operating Expenses	$	312,220	289	%	$	80,356	67	%	$	48,087

N/M Amount is not meaningful

Cost of Crude Oil Sales Cost of crude oil sales is recorded within our Gathering Systems reportable segment. The purchase and sale of crude oil commenced upon closing of the Black Diamond Acquisition during first quarter 2018. An affiliate of Black Diamond enters into agreements to purchase crude oil at market-based prices and sell the crude oil to a different counterparty at market-based prices.

Direct Operating Expenses Direct operating expenses increased during 2018 as compared with 2017 and increased during 2017 as compared with 2016. The increases in direct operating expenses by reportable segment were as follows:

Gathering Systems Gathering Systems direct operating expenses increased $31.3 million during 2018 as compared with 2017. The increases were primarily attributable to operating expenses associated with the CGFs in the Delaware Basin that were completed during 2018, operating expenses associated with the facilities acquired in the Black Diamond Acquisition, and operating expenses associated with the commencement of gathering services in the Mustang IDP during 2018.

Gathering systems direct operating expenses increased $22.7 million during 2017 as compared with 2016. The increase was primarily attributable to an increase in gathering systems and facilities operating expense associated with higher gathered volumes, general repairs and maintenance of our gathering systems and facilities, and produced water services expense resulting from services provided by third parties. The increase was partially offset by a decrease in crude oil treating expense due to a reduction in quantities treated in our facilities.

Fresh Water Delivery Fresh Water Delivery direct operating expenses decreased $(1.7) million during 2018 as compared with 2017 primarily due to decreased volumes resulting from the timing of well completion activity by Noble in the Wells Ranch and East Pony IDP areas and decreased use of third party services.

Fresh Water Delivery direct operating expenses increased $1.6 million during 2017 as compared with 2016 primarily due to an increase in water delivery and services expense driven by an increase in fresh water volumes required per well for higher intensity completions.

Investments and Other Investments and Other direct operating expenses increased $0.9 million during 2018 as compared with 2017 due to increased insurance expense. Investments and Other direct operating expenses increased $0.6 million during 2017 as compared with 2016 primarily due to increased insurance expense. Prior to the IPO, insurance expense was allocated from Noble to our Predecessor.

Depreciation and Amortization Depreciation and amortization expense increased during 2018 as compared with 2017 and increased during 2017 as compared with 2016. The increases in direct operating expenses by reportable segment were as follows:

Gathering Systems Gathering Systems depreciation and amortization expense increased $52.4 million during 2018 as compared with 2017 primarily due to assets placed in service in 2018. Assets placed in service were associated with the expansion of the Wells Ranch CGF and gathering system, construction of the Greeley Crescent gathering system, construction of the Delaware Basin CGFs, and assets acquired in the Black Diamond Acquisition. Additionally, depreciation and amortization expense includes the amortization of intangible assets that consist of customer contracts and relationships acquired in the Black Diamond Acquisition.

Gathering Systems depreciation and amortization expense increased $3.3 million during 2017 as compared with 2016 primarily due to assets placed in service in 2017. Assets placed in service were associated with the expansion of the Wells Ranch CGF

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and gathering system, construction of the Greeley Crescent gathering system, construction of the Delaware Basin gathering system, and completion of the Jesse James and Billy Miner I CGFs.

Fresh Water Delivery Fresh Water Delivery depreciation and amortization expense remained consistent during 2018 as compared with 2017 as fresh water delivery assets in service remained consistent.

Fresh Water Delivery depreciation and amortization expense increased $0.6 million during 2017 as compared with 2016 primarily due to assets placed in service in 2017. Assets placed in service were associated with the construction of the Greeley Crescent fresh water delivery system and expansion of the Mustang fresh water delivery system.

General and Administrative Expense General and administrative expense is recorded within our Investments and Other reportable segment. General and administrative expense increased $10.9 million during 2018 as compared with 2017. The increase is primarily related to legal and financial advisory transaction expenses associated with the Black Diamond Acquisition as well as other professional fees. Transaction expenses associated with the Black Diamond Acquisition during 2018 were approximately $6.8 million. See Item 8. Financial Statements and Supplementary Data – Note 3. Acquisition.

General and administrative expense increased $3.5 million during 2017 as compared with 2016. The increase is primarily due to increased third party general and administrative expenses such as legal and financial advisory fees resulting from transactions.

Other Operating Expense Other operating expense is recorded within our Gathering Systems reportable segment. Other operating expenses incurred during 2018 include losses on the sale of crude oil inventory as well as the net impairment related to a damaged asset.

Other (Income) Expense Trend Analysis

				Increase (Decrease) from Prior Year					Increase (Decrease) from Prior Year
(in thousands)	2018					2017					2016
Year Ended December 31,
Other (Income) Expense
Interest Expense	$	16,848		315	%	$	4,059		(3	)%	$	4,180
Capitalized Interest	(6,356		)	159	%	(2,456		)	204	%	(807		)
Interest Expense, Net	10,492			555	%	1,603			(52	)%	3,373
Investment Income	(16,289		)	157	%	(6,334		)	40	%	(4,526		)
Total Other (Income) Expense	$	(5,797	)	23	%	$	(4,731	)	310	%	$	(1,153	)

Interest Expense, Net Interest expense is recorded within our Investments and Other reportable segment. For periods prior to the IPO, interest expense represents allocations from Noble to our Predecessor. The allocations were based on the percentage that our Predecessor’s capital expenditures comprised of Noble’s total consolidated capital expenditures. For periods subsequent to the IPO, interest expense represents interest incurred in connection with our revolving credit facility and term loan credit facility. Our interest expense includes interest on outstanding balances on the facilities and commitment fees on the undrawn portion of our revolving credit facility as well as the non-cash amortization of origination fees. A portion of the interest expense is capitalized based upon construction-in-progress activity during the year. See Item 8. Financial Statements and Supplementary Data – Note 5. Property, Plant and Equipment for our construction-in-progress balances as of December 31, 2018 and 2017.

Interest expense increased $12.8 million during 2018 as compared with 2017. The increase was primarily due to increased outstanding long-term debt during 2018 as compared with 2017. During 2018, we have utilized proceeds from long-term debt to fund portions of our construction activities and the Black Diamond Acquisition. In addition, interest rates have continued to increase during 2018. Capitalized interest increased $3.9 million during 2018 as compared with 2017 due to an increase in construction-in-progress during 2018 as compared with 2017.

Interest expense decreased $0.1 million during 2017 as compared with 2016. The decrease is due primarily to increased interest expense allocations from Noble during 2016 partially offset by interest incurred in connection with our revolving credit facility during 2017. Capitalized interest increased $1.6 million during 2017 as compared with 2016 due to an increase in construction-in-progress during 2017 as compared with 2016 .

Investment Income

Investment income is recorded within our Investments and Other reportable segment. Investment income increased during 2018 as compared with 2017 due to higher earnings from our investment in the Advantage Joint Venture resulting

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from increased crude oil throughput volumes during 2018 as compared with 2017 as well as a full period of activity from the Advantage Joint Venture which closed during second quarter 2017. Crude oil throughput volumes during 2018 averaged 107 MBbl/d.

Investment income increased during 2017 as compared with 2016 primarily due to earnings from our investment in the Advantage Joint Venture. Crude oil throughput volumes during 2017 averaged 44 MBbl/d.

Income Tax Provision

We are not a taxable entity for U.S. federal income tax purposes or for the majority of states that impose an income tax. Due to our operations in the Delaware Basin, we are subject to a Texas margin tax. Our operations commenced during the third quarter of 2017 and we have recorded de minimis state income tax provisions during each period subsequent to commencement. See Item 8. Financial Statements and Supplementary Data – Note 14. Income Taxes for a discussion of the changes in our income tax provision and effective tax rates.

Adjusted EBITDA (Non-GAAP Financial Measure)

Adjusted EBITDA should not be considered an alternative to net income, net cash provided by operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Adjusted 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 Adjusted EBITDA may not be comparable to similar measures of other companies in our industry.

For a reconciliation of Adjusted EBITDA to its most comparable measures calculated and presented in accordance with GAAP, see Reconciliation of Non-GAAP Financial Measures, below.

We define Adjusted EBITDA as net income (loss) before income taxes, net interest expense, depreciation and amortization, transaction expenses, unit-based compensation and certain other items that we do not view as indicative of our ongoing performance. Adjusted 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 with 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 Adjusted EBITDA provides information useful to investors in assessing our financial condition and results of operations. The GAAP measures most directly comparable to Adjusted EBITDA are net income and net cash provided by operating activities. Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income, net cash provided by operating activities or any other measure as reported in accordance with GAAP.

Distributable Cash Flow (Non-GAAP Financial Measure)

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 similar measures of other companies in our industry.

For a reconciliation of distributable cash flow to its most comparable measures calculated and presented in accordance with GAAP, see Reconciliation of Non-GAAP Financial Measures, below.

We define distributable cash flow as Adjusted EBITDA less estimated maintenance capital expenditures and cash interest paid. Distributable cash flow does not reflect changes in working capital balances. Our partnership agreement requires us to distribute all available cash on a quarterly basis, and distributable cash flow is one of the factors used by the board of directors of our General Partner to help determine the amount of cash that is available to our unitholders for a given period. Therefore, we believe distributable cash flow 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, or more meaningful than, net income, net cash provided by operating activities or any other measure as reported in accordance with GAAP.

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Reconciliation of Non-GAAP Financial Measures

The following tables present reconciliations of Adjusted EBITDA and distributable cash flow to net income and net cash provided by operating activities, the most directly comparable GAAP financial measures, for each of the periods indicated.

Reconciliation of Net Income to Adjusted EBITDA and Distributable Cash Flow

	Year Ended December 31,
(thousands)	2018		2017		2016
Reconciliation from Net Income
Net Income	$	188,876	$	163,636	$	85,502
Add:
Depreciation and Amortization	65,314		12,953		9,066
Interest Expense, Net of Amount Capitalized	10,492		1,603		3,373
Income Tax Provision	221		20		28,288
Transaction and Integration Expenses	7,601		—		—
Unit-Based Compensation and Other	2,392		790		42
Adjusted EBITDA	274,896		179,002		$	126,271
Less:
Adjusted EBITDA Prior to the IPO on September 20, 2016	—		—		83,780
Adjusted EBITDA Subsequent to the IPO on September 20, 2016	274,896		179,002		42,491
Less:
Adjusted EBITDA Attributable to Noncontrolling Interests	53,452		24,493		11,794
Adjusted EBITDA Attributable to Noble Midstream Partners LP	221,444		154,509		30,697
Less:
Maintenance Capital Expenditures	20,439		12,840		2,097
Cash Interest Paid	16,320		3,734		175
Distributable Cash Flow of Noble Midstream Partners LP	$	184,685	$	137,935	$	28,425

Reconciliation of Net Cash Provided by Operating Activities to Adjusted EBITDA and Distributable Cash Flow

	Year Ended December 31,
(thousands)	2018			2017		2016
Reconciliation from Net Cash Provided by Operating Activities
Net Cash Provided by Operating Activities	$	239,797		$	166,228	$	118,451
Add:
Interest Expense, Net of Amount Capitalized	10,492			1,603		3,373
Changes in Operating Assets and Liabilities	17,333			9,756		4,673
Transaction and Integration Expenses	7,601			—		—
Change in Income Tax Payable	221			20		—
Other Adjustments	(548		)	1,395		(226		)
Adjusted EBITDA	274,896			179,002		$	126,271
Less:
Adjusted EBITDA Prior to the IPO on September 20, 2016	—			—		83,780
Adjusted EBITDA Subsequent to the IPO on September 20, 2016	274,896			179,002		42,491
Less:
Adjusted EBITDA Attributable to Noncontrolling Interests	53,452			24,493		11,794
Adjusted EBITDA Attributable to Noble Midstream Partners LP	221,444			154,509		30,697
Less:
Maintenance Capital Expenditures	20,439			12,840		2,097
Cash Interest Paid	16,320			3,734		175
Distributable Cash Flow of Noble Midstream Partners LP	$	184,685		$	137,935	$	28,425

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LIQUIDITY AND CAPITAL RESOURCES

Financing Strategy

Our primary source of liquidity is cash flows generated from operations based on commercial agreements with Noble and unaffiliated third parties. We expect our ongoing sources of liquidity to include cash generated from operations, borrowings under our revolving credit facility, and equity or debt offerings. We believe that cash generated from these sources will be sufficient to meet our short-term working capital requirements, long-term capital expenditure requirements and quarterly cash distributions. 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. Certain consolidated subsidiaries make distributions to or receive contributions from Noble in proportion to Noble’s ownership in such subsidiary.

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 our revolving credit facility and the issuance of debt and equity securities, to fund acquisitions and our expansion capital expenditures.

During 2018, we utilized external financing sources to fund portions of our construction activities and the Black Diamond Acquisition. See Item 8. Financial Statements and Supplementary Data – Note 3. Acquisition and see Item 8. Financial Statements and Supplementary Data – Note 8. Long-Term Debt.

Available Liquidity

Year-end liquidity was as follows:

	December 31,
(in thousands)	2018		2017		2016
Cash, Cash Equivalents, and Restricted Cash (1)	$	11,691	$	55,531	$	57,421
Amount Available to be Borrowed Under Our Revolving Credit Facility (2)	740,000		265,000		350,000
Available Liquidity	$	751,691	$	320,531	$	407,421

⁽¹⁾  See Item 8. Financial Statements and Supplementary Data – Note 2. Summary of Significant Accounting Policies and Basis of Presentation.

⁽²⁾  See Item 8. Financial Statements and Supplementary Data – Note 8. Long-Term Debt.

Revolving Credit Facility and Term Loan Credit Facility

On January 31, 2018, in connection with the closing of the Black Diamond Acquisition, we entered into an amendment to increase the capacity on our revolving credit facility from $350 million to $530 million. On March 9, 2018, we entered into an additional amendment to extend the maturity of our revolving credit facility and increase the borrowing capacity to $800 million. The revolving credit facility is available to fund working capital and to finance acquisitions and expansion capital expenditures. During the year ended December 31, 2018, we utilized our revolving credit facility to fund portions of our construction activities and the Black Diamond Acquisition. See Item 8. Financial Statements and Supplementary Data – Note 3. Acquisition. As of December 31, 2018, $60 million was outstanding under our revolving credit facility. See Item 8. Financial Statements and Supplementary Data – Note 8. Long-Term Debt.

On July 31, 2018, we entered into the term loan credit facility that permitted aggregate borrowings of up to $500 million. During August 2018, we drew $500 million under the term loan credit facility and used the proceeds to repay a portion of the outstanding borrowings under our revolving credit facility and pay fees and expenses in connection with the term loan credit facility transactions. See Item 8. Financial Statements and Supplementary Data – Note 8. Long-Term Debt

Cash Flows

Summary cash flow information was as follows:

	Year Ended December 31,
(in thousands)	2018			2017			2016
Total Cash Provided By (Used in)
Operating Activities	$	239,797		$	166,228		$	118,451
Investing Activities	(1,265,354		)	(362,195		)	(38,137		)
Financing Activities	981,717			194,077			(49,505		)
(Decrease) Increase in Cash and Cash Equivalents	$	(43,840	)	$	(1,890	)	$	30,809

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Operating Activities Net cash provided by operating activities increased during 2018 as compared with 2017 primarily due to an increase of net income driven by increased revenues resulting from higher throughput volumes due to expansion of existing systems and providing services to new areas and customers. The increase in revenues was partially offset by an increase in direct operating expenses resulting from providing services to new areas and customers as well as an increase in general and administrative expense due to legal and financial advisory fees associated with the Black Diamond Acquisition.

Net cash provided by operating activities increased during 2017 as compared with 2016 primarily due to an increase in net income driven by increased revenues resulting from higher throughput volumes due to expansion of existing systems and providing services to new areas and customers.

Investing Activities Cash used in investing activities increased during 2018 as compared with 2017 primarily driven by the Black Diamond Acquisition. Additions to property, plant and equipment were also higher in 2018 due to construction of the Mustang gathering system, expansion of the Mustang fresh water delivery system and construction of the Delaware Basin CGFs.

Cash used in investing activities increased during 2017 as compared with 2016. Additions to property, plant and equipment were higher in 2017 primarily due to the construction of the Greeley Crescent gathering and fresh water delivery system as well as construction of the Delaware Basin gathering system. Additions to investments were also higher in 2017 due to our investment in the Advantage Joint Venture.

Financing Activities Cash provided by financing activities increased during 2018 as compared with 2017. The increase is primarily due to increased net long-term debt borrowings and increased contributions from noncontrolling interest owners which include the contribution from Greenfield Member to fund the Black Diamond Acquisition.

Cash provided by financing activities increased during 2017 as compared with 2016 primarily due to increased contributions from noncontrolling interest owners and net borrowings under our revolving credit facility.

Capital Leases

We may also enter into capital lease arrangements for property or equipment to be used in our business. During third quarter 2016, we entered into a capital lease for a pond to be used in our fresh water delivery system. See Item 8. Financial Statements and Supplementary Data – Note 15. Commitments and Contingencies.

Off-Balance Sheet Arrangements

We have not entered into any transactions, agreements or other contractual arrangements that would result in off-balance sheet liabilities.

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Contractual Obligations

The following table summarizes certain contractual obligations as of December 31, 2018 that are reflected in the consolidated balance sheets and/or disclosed in the accompanying notes.

Obligation	2019		2020 and 2021		2022 and 2023		2024 and Beyond		Total
(in thousands)
Long-Term Debt (1)	$	—	$	500,000	$	60,000	$	—	$	560,000
Long-Term Debt Interest Payments and Revolving Credit Facility Commitment Fee (2)	20,782		34,349		4,358		—		59,489
Asset Retirement Obligations (3)	—		—		—		17,330		17,330
Omnibus Fee (4)	6,850		—		—		—		6,850
Capital Lease Obligations (5)	3,231		—		—		—		3,231
Operating Lease Obligations (6)	1,733		—		—		—		1,733
Purchase Obligations (7)	3,637		—		—		—		3,637
Transportation Fees (8)	1,825		605		—		—		2,430
Surface Lease Obligations (9)	129		259		178		2,180		2,746
Total Contractual Obligations	$	38,187	$	535,213	$	64,536	$	19,510	$	657,446

⁽¹⁾  Long-term debt includes our revolving credit facility and term loan credit facility balances based on the maturity dates of the facilities. See Item 8. Financial Statements and Supplementary Data – Note 8. Long-Term Debt.

⁽²⁾  Interest payments are based on the outstanding balance, scheduled maturity and interest rate in effect at December 31, 2018 for each of the facilities. The commitment fee is associated with the unused portion of the revolving credit facility and is based on the unused capacity as of December 31, 2018, $740 million, for all periods presented with no borrowing capacity increases. See Item 8. Financial Statements and Supplementary Data – Note 8. Long-Term Debt.

⁽³⁾  Asset Retirement Obligations are discounted. See Item 8. Financial Statements and Supplementary Data – Note 9. Asset Retirement Obligations.

⁽⁴⁾  Annual general and administrative fee we pay to Noble for certain administrative and operational support services being provided to us. The annual general and administrative fee cannot be increased until after the third anniversary of the IPO and will be redetermined annually thereafter. See Item 8. Financial Statements and Supplementary Data – Note 4. Transactions with Affiliates.

⁽⁵⁾  Annual capital lease payments exclude regular maintenance and operational costs. See Item 8. Financial Statements and Supplementary Data – Note 15. Commitments and Contingencies.

⁽⁶⁾  Operating lease obligations represent non-cancelable leases for equipment used in our daily operations. Amounts have not been discounted.

⁽⁷⁾  Purchase obligations represent contractual agreements to purchase goods or services that are enforceable, are legally binding and specify all significant terms, including: fixed and minimum quantities to be purchased; fixed, minimum or variable price provisions; and the approximate timing of the transaction. See Item 8. Financial Statements and Supplementary Data – Note 15. Commitments and Contingencies.

⁽⁸⁾  Our transportation fees include fixed fees for the transportation of crude oil. See Item 8. Financial Statements and Supplementary Data – Note 15. Commitments and Contingencies.

⁽⁹⁾  Surface lease obligations represent annual payments to landowners. See Item 8. Financial Statements and Supplementary Data – Note 15. Commitments and Contingencies.

In addition to the above contractual obligations, an affiliate of Black Diamond enters into agreements to purchase crude oil from producers at market-based prices. The agreements do not contain provisions regarding fixed or minimum quantities of crude oil to be purchased.

Capital Requirements

Capital Expenditures and Planned 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. Based on the nature of the expenditure, we categorize our capital expenditures as either:

• maintenance capital expenditures, which are additions to property, plant and equipment made to maintain, over the long term, our production and/or operating income. We use an estimate of maintenance capital expenditures to determine our operating surplus, for purposes of determining cash available for distributions; or

• expansion capital expenditures, which are additions to property, plant and equipment made to construct new midstream infrastructure and those expenditures incurred in order to extend the useful lives of our assets, reduce costs,

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increase revenues or increase system throughput or capacity from current levels, including well connections that increase existing system throughput.

Our planned expansion capital expenditures, driven primarily by Noble’s planned well completions and production growth on our dedicated acreage, will consist primarily of well connections and gathering line additions. We expect to fund at least a portion of future expansion capital expenditures with borrowings under our revolving credit facility. We expect our maintenance capital expenditures to be funded primarily from cash flows from operations.

Capital expenditures and other investing activities (on an accrual basis) were as follows:

	Year Ended December 31,
(in thousands)	2018		2017		2016
Gathering System Expenditures (1)	$	735,425	$	373,857	$	30,020
Fresh Water Delivery System Expenditures	23,018		16,469		2,564
Other	555		—		—
Total Capital Expenditures	$	758,998	$	390,326	$	32,584
Additions to Investments	$	426	$	68,504	$	147

⁽¹⁾  Gathering system expenditures include only the portion of the purchase price for the Black Diamond Acquisition allocated to Property, Plant and Equipment totaling $205.8 million.

For the year ended December 31, 2018, gathering system expenditures were primarily associated with the construction of the Mustang gathering system and construction of CGFs in the Delaware Basin. Additionally, our gathering system expenditures include the Black Diamond Acquisition as well as expenditures related to the connection of the acquired system to a major oil takeaway outlet in the DJ Basin. Fresh water delivery system expenditures were primarily associated with the expansion of the Mustang fresh water delivery system. Our additions to investments during 2018 were related to a capital call for our White Cliffs Interest.

For the year ended December 31, 2017, gathering system expenditures were primarily associated with the construction of the Greeley Crescent, Delaware Basin and Mustang gathering systems, expansion of the Wells Ranch gathering system and construction of the connection from the Billy Miner I CGF in the Delaware Basin to the Advantage pipeline. Fresh water delivery system expenditures were primarily associated with the construction of the Greeley Crescent fresh water delivery system and expansion of the Mustang fresh water delivery system. Our additions to investments during 2017 were related to our investment in the Advantage Joint Venture.

For the year ended December 31, 2016, gathering system expenditures were primarily associated with the construction of the Greeley Crescent, Mustang, and Delaware Basin gathering systems, as well as expansion of the Wells Ranch gathering system. Fresh water delivery system expenditures were primarily related to the expansion of the Wells Ranch, Mustang and East Pony fresh water delivery systems as well as the construction of the Greeley Crescent fresh water delivery system. Our additions to investments during 2016 were related to a capital call for our White Cliffs Interest for an expansion of the pipeline’s crude oil capacity to approximately 215,000 Bbl/d.

Cash Distributions

Our partnership agreement requires that we distribute all of our available cash quarterly. Under our current cash distribution policy, we intend to make distributions of at least the minimum quarterly distribution of $0.375 per unit for each whole quarter, or $1.50 per unit on an annualized basis, to the holders of our Common and Subordinated Units 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. Quarterly distributions, if any, will be made within 45 days after the end of each calendar quarter to holders of record on the applicable record date.

On January 24, 2019, the board of directors of our General Partner declared a quarterly cash distribution of $0.5858 per limited partner unit. The distribution was paid on February 11, 2019, to unitholders of record on February 4, 2019. Also on February 11, 2019, a cash distribution of $2.4 million was paid to Noble related to its IDRs, based upon the level of distribution paid per Common and Subordinated Unit.

For future quarters, the minimum quarterly distribution of $0.375 per unit equates to $14.9 million per quarter, or $59.4 million per year, based on the number of Common and Subordinated Units outstanding as of December 31, 2018.

We expect that if we are successful in executing our business strategy, we will grow our business in a steady and sustainable manner and distribute to our unitholders a portion of any increase in our cash available for distribution resulting from such growth. We expect our general partner may cause us to establish reserves for specific purposes, such as major capital expenditures or debt service payments, or may choose to generally reserve cash in the form of excess distribution coverage

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from time to time for the purpose of maintaining stability or growth in our quarterly distributions. In addition, our general partner may cause us to borrow amounts to fund distributions in quarters when we generate less cash than is necessary to sustain or grow our cash distributions per unit. Our cash distribution policy reflects a judgment that our unitholders will be better served by our distributing rather than retaining our cash available for distribution. 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.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The preparation of the consolidated financial statements requires our management to make a number of estimates and assumptions relating to the reported amounts of assets and liabilities and the disclosures of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the period. When alternatives exist among various accounting methods, the choice of accounting method can have a significant impact on reported amounts. The following is a discussion of the accounting policies, estimates and judgments which management believes are most significant in the application of U.S. GAAP used in the preparation of the consolidated financial statements.

Business Combination We allocate the total purchase price of a business combination, such as the Black Diamond Acquisition, to the assets acquired and the liabilities assumed based on their estimated fair values at the acquisition date, with the excess purchase price recorded as goodwill. See the discussion of goodwill below. Determining the fair value of assets and liabilities acquired, as well as intangible assets that relate to such items as customer contracts and relationships, involves professional judgment and is ultimately based on acquisition models and management’s assessment of the value of the assets acquired and, to the extent available, third party assessments. See the discussion of intangible assets below. An income, market or cost valuation method may be utilized to estimate the fair value of the assets acquired or liabilities assumed at the acquisition date. The income valuation method represents the present value of future cash flows over the life of the assets using: (i) financial forecasts, which rely on management’s estimates of revenue and operating expenses; (ii) long-term growth rates; and (iii) appropriate discount rates. The market valuation method uses prices paid for a reasonably similar asset by other purchasers in the market, with adjustments to reflect differences, such as physical condition and historical performance, between the assets. The cost valuation method is based on the replacement cost of a comparable asset at prices at the time of the acquisition, reduced for depreciation of the asset resulting from physical deterioration and functional or economic obsolescence.

The estimated fair values assigned to assets acquired and liabilities assumed in a purchase price allocation can have a significant effect on future results of operations. For example, a higher fair value assigned to a property, plant and equipment results in higher depreciation and amortization expense, which results in lower net income. In addition, if future operating expenses are higher than the estimates originally used to determine fair value, the resulting reductions in future cash flows could indicate that property, plant and equipment is impaired. See Item 8. Financial Statements and Supplementary Data – Note 3. Acquisition.

Principles of Consolidation The consolidated financial statements include the accounts of our subsidiaries and variable interest entities (VIEs), of which we are the primary beneficiary. A VIE is required to be consolidated by its primary beneficiary, which is generally defined as the party who has (i) the power to direct the activities that most significantly impact the VIE’s economic performance, and (ii) the obligation to absorb losses or the right to receive benefits that could potentially be significant to the VIE. We evaluate our relationships with each VIE, which include each DevCo and Black Diamond, on an ongoing basis to determine whether we continue to be the primary beneficiary. Affiliate or third party ownership interests in our consolidated VIEs are presented as noncontrolling interests. See Item 8. Financial Statements and Supplementary Data – Note 2. Summary of Significant Accounting Policies and Basis of Presentation.

Although we serve as the operator of the Advantage system, our operating agreements empower the Advantage board, split between us and Plains, to direct the activities that most significantly affect the long-term economic performance of the entity, primarily the oversight of the commercial function and approval of expansion capital. As a result, our investment in the Advantage Joint Venture does not require consolidation under the VIE consolidation model. We use the equity method of accounting for our investment in the Advantage Joint Venture, as we do not control, but do exert significant influence over, its operations. See Item 8. Financial Statements and Supplementary Data – Note 2. Summary of Significant Accounting Policies and Basis of Presentation and See Item 8. Financial Statements and Supplementary Data – Note 7. Investments.

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Impairment of Long-Lived Assets Property, plant and equipment are generally stated at the lower of historical cost less accumulated depreciation or fair value, if impaired. Property, plant and equipment balances are evaluated for potential impairment when events or changes in circumstances indicate that their carrying amounts may not be recoverable from expected undiscounted cash flows from the use and eventual disposition of an asset. If the carrying amount of the asset is not expected to be recoverable from future undiscounted cash flows, an impairment may be recognized. Any impairment is measured as the excess of the carrying amount of the asset over its estimated fair value.

In assessing long-lived assets for impairments, our management evaluates changes in our business and economic conditions and their implications for recoverability of the assets’ carrying amounts. A substantial portion of our revenues arise from services provided to Noble. Therefore, significant downward revisions in reserve estimates or changes in future development plans by Noble, to the extent they affect our operations, may necessitate assessment of the carrying amount of our affected assets for recoverability.

Such assessment requires application of judgment regarding the use and ultimate disposition of the asset, long-range revenue and expense estimates, global and regional economic conditions, including commodity prices and drilling activity by our customers, as well as other factors affecting estimated future net cash flows. The measure of impairments to be recognized, if any, depends upon management’s estimate of the asset’s fair value, which may be determined based on the estimates of future net cash flows or values at which similar assets were transferred in the market in recent transactions, if such data is available. During 2018, we recorded an asset impairment of $3.5 million related to a damaged gathering system asset. See Item 8. Financial Statements and Supplementary Data – Note 5. Property, Plant and Equipment.

Goodwill Our goodwill resulted from the Black Diamond Acquisition and represents the excess of the consideration paid over fair value of the net identifiable assets of the acquired business. All of our goodwill is assigned to the Black Diamond reporting unit within the Gathering Systems reportable segment. See Item 8. Financial Statements and Supplementary Data – Note 3. Acquisition and see Item 8. Financial Statements and Supplementary Data – Note 10. Segment Information.

Goodwill is not amortized to earnings but is qualitatively assessed for impairment. We conducted our annual goodwill impairment assessment as of September 30, 2018. Based on the results of the initial qualitative assessment, we concluded that it was more likely than not that the fair value of the Black Diamond reporting unit was in excess of the respective net book values, including goodwill, and, therefore, that goodwill was not impaired. We continue to monitor for impairment indicators, which can lead to further goodwill impairment testing.

Intangible Assets Our intangible assets are comprised of customer contracts and relationships from the Black Diamond Acquisition and were recorded under the acquisition method of accounting at their estimated fair values at the date of acquisition. The customer contracts we acquired are long-term, fixed-fee contracts for the purchase and sale of crude oil. Fair value was calculated using the multi-period excess earnings method under the income approach for the existing customers. This valuation method is based on first forecasting gross profit for the existing customers and then applying expected attrition rates. The operating cash flows were calculated by determining the costs required to generate gross profit from the existing customers. The key assumptions include overall gross profit growth, attrition rate of existing customers over time and the discount rate. 

We utilize the straight-line method of amortization for intangible assets with finite lives. The amortization period is reflective of the benefit pattern in which the estimated economic benefit is expected to be received over the estimated useful life of the intangible asset. The estimated economic benefit was determined by assessing the life of the assets related to the contracts and relationships, likelihood of renewals, competitive factors, regulatory or legal provisions and maintenance costs.

Intangible assets with finite useful lives are reviewed for impairment when events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. No intangible asset impairment has been recognized. See Item 8. Financial Statements and Supplementary Data – Note 3. Acquisition and see Item 8. Financial Statements and Supplementary Data – Note 6. Intangible Assets.

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Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk

We currently generate a substantial portion of our revenues pursuant to fee-based commercial agreements under which we are paid based on the volumes of crude oil, natural gas and produced water that we gather and handle and fresh water services we provide, rather than the underlying value of the commodity.

We have indirect exposure to commodity price risk in that persistent low commodity prices may cause our customers and 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 our customers delay drilling or completion activity, or temporarily shut 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 do not contain minimum volume commitments. Because of the natural decline in production from existing wells, our success, in part, depends on our ability to maintain or increase hydrocarbon and water throughput volumes on our midstream systems, which depends on our customers’ level of drilling and completion activity on our dedicated acreage.

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.

Interest Rate Risk

Our primary exposure to interest rate risk results from outstanding borrowings under our revolving credit facility and term loan credit facility, which have variable interest rates. As of December 31, 2018, $60 million and $500 million were outstanding under our revolving credit facility and term loan credit facility, respectively. A 1.0% increase in our interest rates would have resulted in an estimated $5.0 million increase in interest expense for the year ended December 31, 2018. As a result, our results of operations, cash flows and financial condition and, as a further result, our ability to make cash distributions to our unitholders, could be adversely affected by significant increases in interest rates.

Credit Risk

We derive a substantial portion of our revenue from Noble and we expect to derive a substantial majority of our revenue from Noble for the foreseeable future. As a result, any event, whether in our area of operations or otherwise, that adversely affects Noble’s production, drilling schedule, financial condition, leverage, market reputation, liquidity, results of operations or cash flows may adversely affect our revenues and cash available for distribution.

We are subject to the risk of non-payment or non-performance by Noble, including with respect to our commercial agreements, which do not contain minimum volume commitments. 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 commercial agreements. Any material non-payment or non-performance by Noble under our commercial 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.

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Item 8. Financial Statements and Supplementary Data

INDEX TO FINANCIAL STATEMENTS

Consolidated Financial Statements of Noble Midstream Partners LP
Management’s Report on Internal Control over Financial Reporting	73
Report of Independent Registered Public Accounting Firm (Financial Statements)	74
Report of Independent Registered Public Accounting Firm (Internal Control over Financial Reporting)	75
Consolidated Balance Sheets as of December 31, 2018 and 2017	76
Consolidated Statements of Operations and Comprehensive Income for Each of the Years in the Three-Year Period Ended December 31, 2018	77
Consolidated Statements of Cash Flows for Each of the Years in the Three-Year Period Ended December 31, 2018	78
Consolidated Statements of Changes in Equity in the Three-Year Period Ended December 31, 2018	79
Notes to Consolidated Financial Statements
Note 1. Organization and Nature of Operations	80
Note 2. Summary of Significant Accounting Policies and Basis of Presentation	82
Note 3. Acquisition	88
Note 4. Transactions with Affiliates	90
Note 5. Property, Plant and Equipment	91
Note 6. Intangible Assets	92
Note 7. Investments	93
Note 8. Long-Term Debt	93
Note 9. Asset Retirement Obligations	94
Note 10. Segment Information	95
Note 11. Unit-Based Compensation	96
Note 12. Partnership Distributions	96
Note 13. Net Income Per Limited Partner Unit	97
Note 14. Income Taxes	98
Note 15. Commitments and Contingencies	98
Note 16. Subsequent Events	99
Supplemental Quarterly Financial Information (Unaudited)	100

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Management’s Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting. Our internal control over financial reporting is a process designed under the supervision of our Chief Executive Officer and Chief Financial Officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of consolidated financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America. 

Because of its inherent limitations, internal control over financial reporting may not detect or prevent misstatements. Projections of any evaluation of the effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or processes may deteriorate. 

As of December 31, 2018, our management assessed the effectiveness of our internal control over financial reporting based on the criteria for effective internal control over financial reporting established in Internal Control – Integrated Framework (2013), issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the assessment, management determined that we maintained effective internal control over financial reporting as of December 31, 2018, based on those criteria.

KPMG LLP, the independent registered public accounting firm that audited our consolidated financial statements included in this Annual Report, has issued an attestation report on the effectiveness of internal control over financial reporting as of December 31, 2018 which is included herein.

 

Noble Midstream Partners LP

73

Report of Independent Registered Public Accounting Firm

To the Board of Directors of Noble Midstream GP LLC and

Unitholders of Noble Midstream Partners LP:

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of Noble Midstream Partners LP and subsidiaries (including its Predecessor as defined in note 1 and collectively, the Partnership) as of December 31, 2018 and 2017, the related consolidated statements of operations and comprehensive income, changes in equity, and cash flows for each of the years in the three-year period ended December 31, 2018, and the related notes (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Partnership as of December 31, 2018 and 2017, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2018, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Partnership’s internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control -Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 19, 2019 expressed an unqualified opinion on the effectiveness of the Partnership’s internal control over financial reporting.

Basis for Opinion

These consolidated financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

	/s/ KPMG LLP
We have served as the Partnership’s auditor since 2015.
Houston, Texas
February 19, 2019

74

Report of Independent Registered Public Accounting Firm

To the Board of Directors of Noble Midstream GP LLC and

Unitholders of Noble Midstream Partners LP:

Opinion on Internal Control Over Financial Reporting

We have audited Noble Midstream Partner LP and subsidiaries’ (including its Predecessor as defined in note 1 and collectively, the Partnership) internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. In our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Partnership as of December 31, 2018 and 2017, the related consolidated statement of operations and comprehensive income, changes in equity, and cash flows for each of the years in the three-year period ended December 31, 2018, and the related notes (collectively, the consolidated financial statements), and our report dated February 19, 2019 expressed an unqualified opinion on those consolidated financial statements.

Basis for Opinion

The Partnership’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying management’s report on internal control over financial reporting. Our responsibility is to express an opinion on the Partnership’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control Over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

	/s/ KPMG LLP
Houston, Texas
February 19, 2019

75

Noble Midstream Partners LP

Consolidated Balance Sheets

(in thousands)

	December 31, 2018			December 31, 2017
ASSETS
Current Assets
Cash and Cash Equivalents	$	10,740		$	18,026
Restricted Cash	951			37,505
Accounts Receivable — Affiliate	31,613			27,539
Accounts Receivable — Third Party	23,091			2,641
Crude Oil Inventory	2,200			—
Other Current Assets	2,724			389
Total Current Assets	71,319			86,100
Property, Plant and Equipment
Total Property, Plant and Equipment, Gross	1,500,609			706,039
Less: Accumulated Depreciation and Amortization	(79,357		)	(44,271		)
Total Property, Plant and Equipment, Net	1,421,252			661,768
Intangible Assets, Net	310,202			—
Goodwill	109,734			—
Investments	82,317			80,461
Other Noncurrent Assets	3,093			1,429
Total Assets	$	1,997,917		$	829,758
LIABILITIES
Current Liabilities
Accounts Payable — Affiliate	$	2,778		$	1,616
Accounts Payable — Trade	92,756			109,893
Other Current Liabilities	9,217			2,876
Total Current Liabilities	104,751			114,385
Long-Term Liabilities
Long-Term Debt	559,021			85,000
Asset Retirement Obligations	17,330			10,416
Other Long-Term Liabilities	582			3,727
Total Liabilities	681,684			213,528
EQUITY
Partners’ Equity
Limited Partner
Common Units (23,759 and 23,712 units outstanding, respectively)	699,866			642,616
Subordinated Units (15,903 units outstanding)	(130,207		)	(168,136		)
General Partner	2,421			520
Total Partners’ Equity	572,080			475,000
Noncontrolling Interests	744,153			141,230
Total Equity	1,316,233			616,230
Total Liabilities and Equity	$	1,997,917		$	829,758

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

76

Noble Midstream Partners LP

Consolidated Statements of Operations and Comprehensive Income

(in thousands, except per unit amounts)

	Year Ended December 31,
	2018			2017			2016
Revenues
Midstream Services — Affiliate	$	281,162		$	224,401		$	160,724
Midstream Services — Third Party	72,868			14,880			—
Crude Oil Sales — Third Party	141,490			—			—
Total Revenues	495,520			239,281			160,724
Costs and Expenses
Cost of Crude Oil Sales	136,368			—			—
Direct Operating	84,482			54,007			29,107
Depreciation and Amortization	65,314			12,953			9,066
General and Administrative	24,250			13,396			9,914
Other Operating Expense	1,806			—			—
Total Operating Expenses	312,220			80,356			48,087
Operating Income	183,300			158,925			112,637
Other (Income) Expense
Interest Expense, Net of Amount Capitalized	10,492			1,603			3,373
Investment Income	(16,289		)	(6,334		)	(4,526		)
Total Other (Income) Expense	(5,797		)	(4,731		)	(1,153		)
Income Before Income Taxes	189,097			163,656			113,790
Income Tax Provision	221			20			28,288
Net Income	188,876			163,636			85,502
Less: Net Income Prior to the IPO on September 20, 2016	—			—			45,990
Net Income Subsequent to the IPO on September 20, 2016	188,876			163,636			39,512
Less: Net Income Attributable to Noncontrolling Interests	26,142			23,064			11,054
Net Income Attributable to Noble Midstream Partners LP	162,734			140,572			28,458
Less: Net Income Attributable to Incentive Distribution Rights	5,836			835			—
Net Income Attributable to Limited Partners	$	156,898		$	139,737		$	28,458
Net Income Attributable to Limited Partners Per Limited Partner Common and Subordinated Unit
Basic	$	3.96		$	4.10		$	0.89
Diluted	$	3.96		$	4.10		$	0.89
Weighted Average Limited Partner Units Outstanding — Basic
Common Units	23,686			18,192			15,903
Subordinated Units	15,903			15,903			15,903
Weighted Average Limited Partner Units Outstanding — Diluted
Common Units	23,701			18,204			15,903
Subordinated Units	15,903			15,903			15,903

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

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Noble Midstream Partners LP

Consolidated Statements of Cash Flows

(in thousands)

	Year Ended December 31,
	2018			2017			2016
Cash Flows From Operating Activities
Net Income	$	188,876		$	163,636		$	85,502
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities
Depreciation and Amortization	65,314			12,953			9,066
Asset Impairment	3,470			—			—
Deferred Income Taxes	—			—			28,288
Income from Equity Method Investee, Net of Dividends	(2,661		)	(1,779		)	—
Unit-Based Compensation	1,392			790			42
Other Adjustments for Noncash Items Included in Income	739			384			226
Changes in Operating Assets and Liabilities
Increase in Accounts Receivable	(13,863		)	(12,293		)	(4,637		)
Increase (Decrease) in Accounts Payable	(6,919		)	1,384			(104		)
Other Operating Assets and Liabilities, Net	3,449			1,153			68
Net Cash Provided by Operating Activities	239,797			166,228			118,451
Cash Flows From Investing Activities
Additions to Property, Plant and Equipment	(616,383		)	(294,664		)	(41,115		)
Black Diamond Acquisition, Net of Cash Acquired	(649,868		)	—			—
Additions to Investments	(426		)	(68,504		)	(147		)
Distributions from Cost Method Investee	1,323			973			1,275
Proceeds from Asset Sale — Affiliate	—			—			1,850
Net Cash Used in Investing Activities	(1,265,354		)	(362,195		)	(38,137		)
Cash Flows From Financing Activities
Distributions to Parent	—			—			(42,480		)
Contributions from Parent	—			—			1,036
Proceeds from IPO, Net of Cash Offering Costs	—			—			300,625
Distribution to Noble Subsequent to the IPO	—			—			(296,820		)
Distributions to Noncontrolling Interests	(9,257		)	(21,737		)	(10,057		)
Cash Contributions from Noncontrolling Interests	605,864			124,684			325
Borrowings Under Revolving Credit Facility	777,000			325,000			—
Repayment of Revolving Credit Facility	(802,000		)	(240,000		)	—
Proceeds from Term Loan Credit Facility	500,000			—			—
Proceeds from Equity Offerings, Net of Cash Offering Costs	—			312,579			—
Distribution to Noble for Contributed Assets	—			(245,000		)	—
Distributions to Unitholders	(86,841		)	(59,917		)	—
Repayment of Capital Lease Obligation	—			(1,532		)	(214		)
Debt Issuance Costs and Other	(3,049		)	—			(1,920		)
Net Cash Provided by (Used in) Financing Activities	981,717			194,077			(49,505		)
(Decrease) Increase in Cash, Cash Equivalents, and Restricted Cash	(43,840		)	(1,890		)	30,809
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	55,531			57,421			26,612
Cash, Cash Equivalents, and Restricted Cash at End of Period	$	11,691		$	55,531		$	57,421

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

78

Noble Midstream Partners LP

Consolidated Statements of Changes in Equity

(in thousands)

	Predecessor			Partnership
	Parent Net Investment			Common Units			Subordinated Units			General Partner			Noncontrolling Interests			Total
December 31, 2015	$	263,539		$	—		$	—		$	—		$	—		$	263,539
Net Income, January 1, 2016 to September 19, 2016	45,990			—			—			—			—			45,990
Contributions from Parent	1,155			—			—			—			—			1,155
Distributions to Parent	$	(42,480	)	$	—		$	—		$	—		$	—		$	(42,480	)
September 19, 2016 (Prior to the IPO)	$	268,204		$	—		$	—		$	—		$	—		$	268,204
Elimination of Current and Deferred Tax Liability	41,428						—			—			—			41,428
Allocation of Net Investment to Unitholders	(309,632		)	21,112			219,779			—			68,741			—
Proceeds from IPO, Net of Offering Costs	—			298,968			—			—			—			298,968
Proceeds from IPO Distributed to Noble	—			(26,013		)	(270,807		)	—			—			(296,820		)
Net Income, Subsequent to the IPO on September 20, 2016	—			14,229			14,229			—			11,054			39,512
Unit-Based Compensation	—			42			—			—			—			42
Contributions from Noncontrolling Interests(1)	—			—			—			—			1,628			1,628
Distributions to Noncontrolling Interests	—			—			—			—			(10,057		)	(10,057		)
December 31, 2016	$	—		$	308,338		$	(36,799	)	$	—		$	71,366		$	342,905
Net Income	—			75,076			64,661			835			23,064			163,636
Contributions from Noncontrolling Interests	—			—			—			—			123,381			123,381
Distributions to Noncontrolling Interests	—			—			—			—			(21,737		)	(21,737		)
Distributions to Unitholders	—			(31,672		)	(27,930		)	(315		)	—			(59,917		)
Net Proceeds from Offerings	—			312,172			—			—			—			312,172
Distribution to Noble for Contributed Assets	—			(28,459		)	(216,541		)	—			—			(245,000		)
Contributed Assets Transfer from Noble	—			6,371			48,473			—			(54,844		)	—
Unit-Based Compensation	—			790			—			—			—			790
December 31, 2017	$	—		$	642,616		$	(168,136	)	$	520		$	141,230		$	616,230
Net Income	—			93,875			63,023			5,836			26,142			188,876
Contributions from Noncontrolling Interests	—			—			—			—			605,864			605,864
Distributions to Noncontrolling Interests	—			—			—			—			(9,257		)	(9,257		)
Distributions to Unitholders	—			(49,610		)	(33,296		)	(3,935		)	—			(86,841		)
Black Diamond Equity Ownership Promote Vesting (2)	—			11,624			8,202			—			(19,826		)	—
Unit-Based Compensation	—			1,392			—			—			—			1,392
Other	—			(31		)	—			—			—			(31		)
December 31, 2018	$	—		$	699,866		$	(130,207	)	$	2,421		$	744,153		$	1,316,233

⁽¹⁾  Includes an outstanding cash call as of December 31, 2016.

⁽²⁾  See Note 2. Summary of Significant Accounting Policies and Basis of Presentation for further discussion of the Black Diamond equity ownership promote vesting.

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

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Table of Contents	Noble Midstream Partners LP
Index to Financial Statements	Notes to Consolidated Financial Statements

Note 1. Organization and Nature of Operations

Organization We are a growth-oriented Delaware master limited partnership formed in December 2014 by Noble to own, operate, develop and acquire a wide range of domestic midstream infrastructure assets. Our current areas of focus are in the DJ Basin and the Delaware Basin.

Initial Public Offering On September 20, 2016, we completed the IPO of 14,375,000 Common Units representing limited partner interests in the Partnership (Common Units), which included 1,875,000 Common Units issued pursuant to the underwriters’ exercise of their option to purchase additional Common Units, at a price to the public of $22.50 per Common Unit ($21.20625 per Common Unit, net of underwriting discounts). In connection with the IPO, Noble contributed ownership interests in certain DevCos and a 3.33% ownership interest in White Cliffs. The ownership interests in the DevCos, together with the White Cliffs Interest, are referred to collectively as the Contributed Businesses.

Advantage Joint Venture Trinity River DevCo LLC, an indirect wholly owned subsidiary of the Partnership, and Plains Pipeline, L.P. (Plains), a wholly owned subsidiary of Plains All American Pipeline, L.P., completed the acquisition of Advantage Pipeline, L.L.C. (Advantage) for $133 million through a newly formed 50/50 joint venture (the Advantage Joint Venture). Trinity River DevCo LLC contributed $66.8 million of cash in exchange for its 50% interest in the Advantage Joint Venture. We serve as the operator of the Advantage system, which includes a 70-mile crude oil pipeline in the Southern Delaware Basin from Reeves County, Texas to Crane County, Texas, with 200,000 barrels of daily shipping capacity and 490,000 barrels of storage capacity. The Partnership funded the acquisition with a combination of borrowings under our revolving credit facility and from cash on hand. The transaction closed on April 3, 2017. See Note 7. Investments.

Contribution Agreement On June 20, 2017, the Partnership entered into a Contribution Agreement (the Contribution Agreement) by and among the Partnership, Noble Midstream GP LLC, our General Partner, Noble Midstream Services, LLC (Midstream Services), NBL Midstream, LLC (NBL Midstream), a subsidiary of Noble, and Blanco River DevCo GP LLC (Blanco River DevCo GP). Pursuant to the terms of the Contribution Agreement, the Partnership agreed to acquire from NBL Midstream (i) the remaining 20% limited partner interest in Colorado River DevCo LP and (ii) an additional 15% limited partner interest in Blanco River DevCo LP (collectively, the Contributed Assets). In consideration for the Contributed Assets, the Partnership agreed to pay NBL Midstream $270 million, consisting of (i) $245 million in cash and (ii) 562,430 Common Units issued to NBL Midstream at an issue price of $44.45 per common unit, the closing price of our Common Units on the New York Stock Exchange on June 20, 2017 (the Transaction). The Transaction closed on June 26, 2017. The Partnership funded the cash consideration with a combination of borrowings under our revolving credit facility, proceeds from the Private Placement (as defined below), and from cash on hand.

Prior to the acquisition of the Contributed Assets, the Contributed Assets were reflected as noncontrolling interests in the Partnership’s consolidated financial statements. As the Partnership acquired additional interests in already-consolidated entities, the acquisition did not result in a change in reporting entity, as defined under the Financial Accounting Standards Board (FASB) Accounting Standards Codification Topic 805, Business Combinations, and was accounted for on a prospective basis. Therefore, beginning June 26, 2017, the Partnership’s consolidated financial statements reflect its 100% ownership interest in Colorado River DevCo LP and its 40% ownership interest in Blanco River DevCo LP.

Private Placement On June 20, 2017, the Partnership entered into a Common Unit Purchase Agreement with certain institutional investors, pursuant to which the Partnership agreed to sell 3,525,000 Common Units in a private placement for gross proceeds of approximately $142.6 million (the Private Placement). Net proceeds totaled approximately $138.0 million, after deducting offering expenses of approximately $4.6 million. The closing of the Private Placement occurred on June 26, 2017.

Unit Offering On December 12, 2017, the Partnership entered into an Underwriting Agreement (the Underwriting Agreement) by and among the Partnership, our General Partner, and Citigroup Global Markets Inc., as representative of the several underwriters named therein (the Underwriters), providing for the offer and sale by the Partnership, and the purchase by the Underwriters of 3,680,000 Common Units, which includes 480,000 Common Units issued pursuant to the Underwriters’ exercise of their option to purchase additional Common Units, at a price of $47.50 per common unit (the Unit Offering). Net proceeds totaled approximately $174.1 million, after deducting offering expenses of approximately $0.7 million. The closing of the Unit Offering occurred on December 15, 2017.

Black Diamond Gathering LLC On January 31, 2018, Black Diamond, an entity formed by Black Diamond Gathering Holdings LLC (the Noble Member), a wholly-owned subsidiary of Noble Midstream Partners LP, and Greenfield Midstream, LLC (the Greenfield Member), completed the acquisition of all of the issued and outstanding limited liability company interests (the Black Diamond Acquisition) in Saddle Butte Rockies Midstream, LLC and certain affiliates (collectively, Saddle Butte) from Saddle Butte Pipeline II, LLC (Seller). See Note 3. Acquisition.

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Index to Financial Statements	Notes to Consolidated Financial Statements

Partnership Assets Our assets consist of ownership interests in certain development companies (DevCos) which serve specific areas and integrated development plan (IDP) areas and consist of the following:

DevCo	Areas Served	NBLX Dedicated Service	NBLX Ownership	Noncontrolling Interest(1)
Colorado River DevCo LP	Wells Ranch IDP (DJ Basin) East Pony (DJ Basin) All Noble DJ Basin Acreage	Crude Oil Gathering Natural Gas Gathering Water Services Crude Oil Gathering Crude Oil Treating	100%	N/A
San Juan River DevCo LP	East Pony IDP (DJ Basin)	Water Services	25%	75%
Green River DevCo LP	Mustang IDP (DJ Basin)	Crude Oil Gathering Natural Gas Gathering Water Services	25%	75%
Laramie River DevCo LP (2)	Greeley Crescent IDP (DJ Basin)	Crude Oil Gathering Water Services	100%	N/A
	Black Diamond Dedication Area (DJ Basin)	Crude Oil Gathering Natural Gas Gathering	54.4%	45.6%
Blanco River DevCo LP	Delaware Basin	Crude Oil Gathering Natural Gas Gathering Water Services	40%	60%
Gunnison River DevCo LP	Bronco IDP (DJ Basin) (3)	Crude Oil Gathering Water Services	5%	95%
Trinity River DevCo LLC (4)	Delaware Basin	Natural Gas Compression Crude Oil Transmission	100%	N/A

⁽¹⁾  The noncontrolling interest represents Noble’s retained ownership interest in each DevCo. The noncontrolling interest in Black Diamond represents Greenfield Member's interest in Black Diamond.

⁽²⁾  Our interest in Black Diamond is owned through Laramie River DevCo LP. See Note 2. Summary of Significant Accounting Policies and Basis of Presentation and Note 3. Acquisition.

⁽³⁾  The Bronco IDP is a future development area. We currently have no midstream infrastructure assets in the Bronco IDP.

⁽⁴⁾  Our interest in the Advantage Joint Venture is owned through Trinity River DevCo LLC.

Additionally, we own a 3.33% ownership interest in White Cliffs as well as a 50% interest in the Advantage Joint Venture.

Nature of Operations Through our ownership interests in the DevCos, we operate and own interests in the following assets, some of which are currently under construction:

• crude oil gathering systems;

• natural gas gathering systems and compression units;

• crude oil treating facilities;

• produced water collection, gathering, and cleaning systems; and

• fresh water storage and delivery systems.

We generate revenues primarily by charging fees on a per unit basis for gathering crude oil and natural gas, delivering and storing fresh water, and collecting, cleaning and disposing of produced water. Additionally, we purchase crude oil from producers and sell crude oil to customers at various delivery points on our gathering systems. We have entered into multiple fee-based commercial agreements with Noble, each with an initial term of 15 years, to provide these services which are critical to Noble’s upstream operations. Our agreements include substantial acreage dedications. See Note 4. Transactions with Affiliates.

Predecessor References in this report to “Predecessor,” “we,” “our,” “us” or like terms, when referring to periods prior to September 20, 2016, refer to Noble’s Contributed Businesses, our Predecessor for accounting purposes. References to “the Partnership,” “we,” “our," “us” or like terms, when referring to periods after September 20, 2016, refer to the partnership.

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Index to Financial Statements	Notes to Consolidated Financial Statements

Note 2. Summary of Significant Accounting Policies and Basis of Presentation

Basis of Presentation and Consolidation   The accompanying consolidated financial statements for periods prior to September 20, 2016 represent the Contributed Businesses as the accounting Predecessor to the Partnership, presented on a carve-out basis of Noble’s historical ownership of the Predecessor. The Predecessor financial statements have been prepared from the separate records maintained by Noble and may not necessarily be indicative of the actual results of operations that might have occurred if the Predecessor had been operated separately during the periods reported. Because a direct ownership relationship did not exist among the businesses comprising the Predecessor, the net investment in the Predecessor is shown as Parent Net Investment, in lieu of partners’ equity, in the accompanying Consolidated Statement of Changes in Equity for years prior to December 31, 2016. All intercompany balances and transactions have been eliminated upon consolidation.

The Partnership has no items of other comprehensive income or loss; therefore, its net income is identical to its comprehensive income.

Variable Interest Entities  Our consolidated financial statements include our accounts and the accounts of the DevCos, each of which we control as General Partner. All intercompany balances and transactions have been eliminated upon consolidation. We have determined that the partners with equity at risk in each of the DevCos lack the authority, through voting rights or similar rights, to direct the activities that most significantly impact their economic performance. Therefore, each DevCo is considered a variable interest entity (VIE). Through our 100% ownership interest in Noble Midstream Services, LLC, a Delaware limited liability company which owns controlling interests in each of the DevCos, we have the authority to direct the activities that most significantly affect economic performance and the obligation to absorb losses or the right to receive benefits that could be potentially significant to us. Therefore, we are considered the primary beneficiary and consolidate each of the DevCos in our financial statements. A substantial portion of the financial statement activity associated with our DevCos is captured within the Gathering Systems and Fresh Water Delivery reportable segments. Although our investment in the Advantage Joint Venture is owned by Trinity River DevCo LLC, all financial statement activity associated with our investment is captured within the Investments and Other reportable segment. See Note 10. Segment Information.

Our consolidated financial statements include the accounts of Black Diamond, which we control. We have determined that the partners with equity at risk in Black Diamond lack the authority, through voting rights or similar rights, to direct the activities that most significantly impact their economic performance. Therefore, Black Diamond is considered a VIE. Through our majority representation on the Black Diamond board of directors as well as our responsibility as operator of the Black Diamond system, we have the authority to direct the activities that most significantly affect economic performance and the obligation to absorb losses or the right to receive benefits that could be potentially significant to us. Therefore, we are considered the primary beneficiary and consolidate Black Diamond in our financial statements.

Equity Method of Accounting Although we serve as the operator of the Advantage system, our operating agreements empower the Advantage board, split between us and Plains, to direct the activities that most significantly affect the long-term economic performance of the entity, primarily the oversight of the commercial function and approval of expansion capital. As a result, our investment in the Advantage Joint Venture does not require consolidation under the VIE consolidation model. We use the equity method of accounting for our investment in the Advantage Joint Venture, as we do not control, but do exert significant influence over, its operations. Under the equity method of accounting, initially we record the investment at our cost. Differences in the cost, or basis, of the investment and the net asset value of the investee will be amortized into earnings over the remaining useful life of the underlying assets. See Note 7. Investments.

Cost Method of Accounting We use the cost method of accounting for our White Cliffs Interest as we have virtually no influence over its operations and financial policies. Under the cost method of accounting, we recognize cash distributions from White Cliffs Pipeline L.L.C. as investment income in our consolidated statements of operations to the extent there is net income and record cash distributions in excess of our ratable share of earnings as return of investment. See Note 7. Investments.

Noncontrolling Interests We present our consolidated financial statements with a noncontrolling interest section representing Noble’s retained ownership our DevCos as well as Greenfield Member’s ownership of Black Diamond.

Black Diamond Equity Ownership Promote Vesting In accordance with the limited liability company agreement of Black Diamond, Noble Member received an equity ownership promote. The capital accounts for Noble Member and Greenfield Member at December 31, 2018 do not equal their agreed equity ownership interests due to the funding structure of the total Black Diamond Acquisition purchase price. See Note 3. Acquisition.

The limited liability company agreement of Black Diamond requires special allocations of gross income to balance the ratio of each member’s capital account to their agreed equity ownership interest over time. The special allocations are accounted for as equity transactions between the Partnership and a subsidiary with no gain or loss recognized.

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Segment Information   Accounting policies for reportable segments are the same as those described in this footnote. Transfers between segments are accounted for at market value. We do not consider interest income and expense or income tax benefit or expense in our evaluation of the performance of reportable segments. See Note 10. Segment Information.

Use of Estimates   The preparation of consolidated financial statements in conformity with U.S. 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 consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ significantly from those estimates. Management evaluates estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment.

Intangible Assets Our intangible assets are comprised of customer contracts and related relationships acquired in the Black Diamond Acquisition and recorded under the acquisition method of accounting at their estimated fair values at the date of acquisition. Amortization is calculated using the straight-line method by customer contract, which reflects the pattern in which the estimated economic benefit is expected to be received over the estimated useful life of the intangible asset. The amortization of intangible assets is included in depreciation and amortization expense in our consolidated statements of operations. Intangible assets with finite useful lives are reviewed for impairment when events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. See Note 3. Acquisition and Note 6. Intangible Assets.

Goodwill As of December 31, 2018, our consolidated balance sheet includes goodwill of $109.7 million. This goodwill resulted from the Black Diamond Acquisition and represents the excess of the consideration paid over fair value of the net identifiable assets of the acquired business. All of our goodwill is assigned to the Black Diamond reporting unit within the Gathering Systems reportable segment. See Note 3. Acquisition and Note 10. Segment Information.

Goodwill is not amortized to earnings but is qualitatively assessed for impairment. Goodwill is assessed for impairment annually during the third quarter, or more frequently as circumstances require, at the reporting unit level. If, based on our qualitative assessment, it is more likely than not that the fair value of the reporting unit is less than its carrying amount, we will perform a quantitative assessment. If, based on our quantitative assessment, we conclude that it is more likely than not that the fair value of a reporting unit is less than its carrying amount, an impairment charge is recognized for the amount by which the carrying amount exceeds the fair value.

Crude Oil Inventory Our crude oil inventory consists of crude oil that has been purchased at the wellhead. Our crude oil inventory is stated at the lower of cost or net realizable value.

Property, Plant and Equipment Property and equipment primarily consists of crude oil gathering systems, natural gas gathering systems and compression units, produced water collection, gathering, and cleaning systems, fresh water storage and delivery systems and crude oil treating facilities. Property and equipment is stated at the lower of historical cost less accumulated depreciation, or fair value, if impaired.

Capitalized Interest We capitalize construction-related direct labor and incremental costs, such as interest expense. Capitalized interest totaled $6.4 million in 2018, $2.5 million in 2017, and $0.8 million in 2016.

Depreciation Depreciation is computed over the asset’s estimated useful life using the straight line method based on estimated useful lives and asset salvage values. Determination of depreciation expense requires judgment regarding the estimated useful lives and salvage values of property, plant and equipment. As circumstances warrant, depreciation estimates are reviewed to determine if any changes in the underlying assumptions are necessary. The weighted average life of our long-lived assets is 30 years. The depreciation of fixed assets recorded under capital lease agreements is included in depreciation and amortization expense. See Note 5. Property, Plant and Equipment.

Impairment of Long-Lived Assets We routinely assess whether impairment indicators arise during any given quarter and have processes in place to ensure that we become aware of such indicators. Impairment indicators include, but are not limited to, sustained decreases in commodity prices, a decline in customer well results and lower throughput forecasts, and increases in construction or operating costs. In the event that impairment indicators exist, we conduct an impairment test.

We evaluate our ability to recover the carrying amounts of long-lived assets and determine whether such long-lived assets have been impaired. Impairment exists when the carrying value of an asset exceeds the estimated undiscounted future cash flows expected to result from the use and eventual disposition of the asset. When the carrying amount of a long-lived asset exceeds its estimated undiscounted future cash flows, the carrying amount of the asset is reduced to its estimated fair value. Fair value may be estimated using comparable market data, a discounted cash flow method, or a combination of the two. During 2018, we recorded an asset impairment of $3.5 million related to a damaged gathering system asset. The asset impairment was partially offset by an insurance recovery of $2.5 million. The resulting net impairment totaled $1.0 million and is recorded within other operating expense in our consolidated statement of operations.

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Index to Financial Statements	Notes to Consolidated Financial Statements

Asset Retirement Obligations  Asset Retirement Obligations (AROs) consist of estimated costs of dismantlement, removal, site reclamation and similar activities associated with our property and equipment. 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 and amortization. See Note 9. Asset Retirement Obligations.

Impairment of Investments We routinely assess our investments for impairment whenever changes in facts and circumstances indicate a loss in value has occurred. When impairment indicators exist, the fair value is estimated and compared to the investment carrying amount. When the carrying amount of an investment exceeds its estimated undiscounted future cash flows, the carrying amount of the investment is reduced to its estimated fair value. Fair value may be estimated using comparable market data, a discounted cash flow method, or a combination of the two. No impairments have been recorded through December 31, 2018.

Fair Value Measurements Fair value measurements are based on a hierarchy which prioritizes the inputs to valuation techniques used to measure fair value into three levels. The fair value hierarchy is as follows:

• Level 1 measurements are fair value measurements which use quoted market prices (unadjusted) in active markets for identical assets or liabilities.

• Level 2 measurements are fair value measurements which use inputs, other than quoted prices included within Level 1, which are observable for the asset or liability, either directly or indirectly.

• Level 3 measurements are fair value measurements which use unobservable inputs.

We measure assets and liabilities requiring fair value presentation and disclose such amounts according to the quality of valuation inputs under the fair value hierarchy. The carrying amounts of our cash and cash equivalents, accounts receivable and accounts payable approximate fair value due to the short-term nature and maturity of the instruments and use Level 1 inputs.

Our revolving credit facility and term loan credit facility are variable-rate, non-public debt. The fair value of our revolving credit facility and term loan credit facility is equivalent to the carrying amount. The fair value is estimated based on significant other observable inputs. As such, we consider the fair value of these facilities to be a Level 2 measurement on the fair value hierarchy. See Note 8. Long-Term Debt.

The fair value of the intangible assets acquired as part of the Black Diamond acquisition is determined using unobservable inputs and is considered to be a Level 3 measurement on the fair value hierarchy. See Note 6. Intangible Assets

Certain assets and liabilities, such as property, plant, and equipment, goodwill and other intangible assets, are not required to be measured at fair value on a recurring basis. However, these assets are assessed for impairment, and a resulting impairment would require the asset be recorded at fair value.

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.

Transactions with Affiliates Transactions between Noble, its affiliates and us have been identified in the consolidated financial statements as transactions with affiliates. See Note 4. Transactions with Affiliates.

Capital Lease Obligation   We entered into a capital lease for a pond to be used in our fresh water delivery system. The amount of the capital lease obligation is based on the discounted present value of future minimum lease payments, and therefore does not reflect future cash lease payments. See Note 15. Commitments and Contingencies.

Unit-Based Compensation Unit-based compensation issued to individuals providing services to us is recorded at grant-date fair value. Expense is recognized on a straight-line basis over the requisite service period (generally the vesting period of the award) in the consolidated statements of operations. See Note 11. Unit-Based Compensation.

Income Taxes We are not a taxable entity for United States federal income tax purposes or for the majority of states that impose an income tax. As taxes are generally borne by our partners through the allocation of taxable income, we do not record deferred taxes related to the aggregate difference in the basis of our assets for financial and tax reporting purposes. During third

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quarter 2017, we commenced operations in the Delaware Basin and are subject to a Texas margin tax. The tax due is based on an entity’s apportioned taxable margin.

For periods prior to the IPO, our consolidated financial statements include a provision for tax expense on income related to the assets that Noble contributed to the Partnership at the IPO date. Deferred federal and state income taxes were provided on temporary differences between the financial statement carrying amounts of recognized assets and liabilities and their respective tax bases as if the Partnership filed tax returns as a stand-alone entity. See Note 14. Income Taxes.

Litigation and Other Contingencies We may become subject to legal proceedings, claims and liabilities that will arise in the ordinary course of business. We will accrue for losses associated with legal claims when such losses are considered probable and the amounts can be reasonably estimated. See Note 15. Commitments and Contingencies.

Supplemental Cash Flow Information We accrued $72.6 million and $99.8 million related to midstream capital expenditures as of December 31, 2018 and 2017, respectively.

Greenfield Member contributed approximately $18.8 million of the amount held in escrow at December 31, 2017 for the purchase of Saddle Butte. See the Reconciliation of Total Cash below.

Immediately prior to closing of the IPO, the Partnership recorded an adjustment to equity of $41.4 million for the elimination of current and deferred tax liabilities, representing a significant non-cash activity.

Cash interest paid totaled $16.3 million and $3.7 million for the years ended December 31, 2018 and December 31, 2017, respectively. Prior to closing of the IPO, interest expense was allocated to us from Noble.

Concentration of Credit Risk For the year ended December 31, 2018, revenues from Noble and its affiliates comprised 79% and 57% of our midstream services revenues and total revenues, respectively. Revenues from a single third party customer, Stanchion Energy, LLC, comprised 66% and 19% of our crude oil sales revenues and total revenues, respectively.

For the years ended December 31, 2017 and 2016, revenues from Noble and its affiliates comprised 94% and 100% of our total revenues, respectively.

Recently Adopted Accounting Standards

Clarifying the Definition of a Business In January 2017, the FASB issued Accounting Standards Update No. 2017-01 (ASU 2017-01): Business Combinations - Clarifying the Definition of a Business. ASU 2017-01 assists in determining whether certain transactions should be accounted for as acquisitions or dispositions of assets or businesses. The amendment provides a screen to be applied to the fair value of an acquisition or disposal to evaluate whether the assets in question are simply assets or if they meet the definition of a business. If the screen is not met, no further evaluation is needed. If the screen is met, certain steps are subsequently taken to make the determination. We adopted ASU 2017-01 in the first quarter of 2018 and have applied the guidance to the Black Diamond Acquisition.

Statement of Cash Flows – Restricted Cash In November 2016, the FASB issued Accounting Standards Update No. 2016-18 (ASU 2016-18): Statement of Cash Flows - Restricted Cash. We adopted ASU 2016-18 in the first quarter of 2018, using the retrospective method. ASU 2016-18 requires that restricted cash and cash equivalents be included with cash and cash equivalents when reconciling the total beginning and ending amounts for the periods shown on the statement of cash flows, but has no other impacts on our results of operations, financial condition or cash flows.

Topic 606, Revenue from Contracts with Customers  In May 2014, the FASB issued Accounting Standards Update No. 2014-09 (ASU 2014-09), which creates Topic 606, Revenue from Contracts with Customers (ASC 606). We adopted ASC 606 on January 1, 2018, using the modified retrospective method. See our Revenue Recognition discussion below.

Intangibles – Goodwill and Other: Simplifying the Test for Goodwill Impairment In January 2017, the FASB issued Accounting Standards Update No. 2017-04 (ASU 2017-04): Intangibles – Goodwill and Other – Simplifying the Test for Goodwill Impairment, to simplify how an entity is required to test goodwill for impairment by eliminating Step 2 from the goodwill impairment test. Step 2 measures a goodwill impairment loss by comparing the implied fair value of a reporting unit’s goodwill with the carrying amount of that goodwill. Under the new standard, we will perform our goodwill impairment test by performing a qualitative test to determine if a quantitative test is necessary. The quantitative test will compare the fair value of a reporting unit with its carrying amount, with an impairment charge being recognized for the amount by which the carrying amount exceeds the reporting unit’s fair value. ASU 2017-04 will be effective for annual or any interim goodwill impairment tests in fiscal years beginning after December 15, 2019, with early adoption permitted. We early adopted this ASU in fourth quarter 2018. This adoption did not have a material impact on our financial statements.

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Index to Financial Statements	Notes to Consolidated Financial Statements

Recently Issued Accounting Standards

Leases In February 2016, the FASB issued Accounting Standards Update No. 2016-02 (ASU 2016-02): Leases. The standard requires lessees to recognize a right of use asset and lease liability on the balance sheet for the rights and obligations created by leases with terms of more than 12 months. ASU 2016-02 also requires disclosures designed to give financial statement users information on the amount, timing, and uncertainty of cash flows arising from leases. In July 2018, the FASB issued Accounting Standards Update No. 2018-11 (ASU 2018-11): Leases (Topic 842): Targeted Improvements, which provides for an alternative transition method by allowing entities to initially apply the new leases standard at the adoption date (such as January 1, 2019) and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption (i.e. comparative periods presented in the financial statements will continue to be in accordance with current GAAP (Topic 840, Leases)). The standard will be effective for annual and interim periods beginning after December 15, 2018, with earlier application permitted.

In the normal course of business, we enter into lease agreements and land easements to support our operations and may lease water-related, field-related and other assets. We will adopt the new standard on the effective date of January 1, 2019 using a modified retrospective approach as permitted under ASU 2018-11.

The new standard provides a number of optional practical expedients in transition. We expect to:

• elect the package of ‘practical expedients’, which permits us not to reassess under the new standard our prior conclusions about lease identification, lease classification and initial direct costs;

• adopt the practical expedient pertaining to land easements and plan to account for existing land easements under our current accounting policy;

• elect the short-term lease recognition exemption for all leases that qualify and as such, no right-of-use (ROU) asset or lease liability will be recorded on the balance sheet and no transition adjustment will be required for short-term leases; and

• elect the practical expedient to not separate lease and non-lease components for all of our leases.

We do not expect to elect the hindsight practical expedient in determining the lease term and assessing impairment of ROU assets when transitioning to ASC 842.

We continue to execute a project plan, which includes contract review and assessment, data collection, and evaluation of our systems, processes and internal controls. In addition, we implemented a new lease accounting software which will facilitate in the adoption of this standard.

The adoption and implementation of this standard will not have a material effect on our financial statements. While we are finalizing our assessment of the effect of adoption, we estimate the most significant impact will relate to the recognition of new ROU assets and lease liabilities on our balance sheet for operating leases, as well as additional disclosures. Consequently, with adoption, we expect to recognize additional operating liabilities ranging between $1 million to $3 million with corresponding ROU assets of the same amount based on the present value of the remaining minimum rental payments under current leasing standards for existing operating leases.

Intangibles—Goodwill and Other—Internal-Use Software In August 2018, the FASB issued Accounting Standards Update No. 2018-15 (ASU 2018-15): Intangibles—Goodwill and Other—Internal-Use Software, to align the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software. The amended standard is effective for fiscal years beginning after December 15, 2019, with early adoption permitted. We are currently evaluating the provisions of ASU 2018-15.

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Reconciliation of Total Cash We define total cash as cash, cash equivalents and restricted cash. The following table provides a reconciliation of total cash:

	Twelve Months Ended December 31,
(in thousands)	2018		2017		2016
Cash and Cash Equivalents at Beginning of Period	$	18,026	$	57,421	$	26,612
Restricted Cash at Beginning of Period (1)	37,505		—		—
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	$	55,531	$	57,421	$	26,612
Cash and Cash Equivalents at End of Period	$	10,740	$	18,026	$	57,421
Restricted Cash at End of Period (1) (2)	951		37,505		—
Cash, Cash Equivalents, and Restricted Cash at End of Period	$	11,691	$	55,531	$	57,421

⁽¹⁾  Restricted cash represents the amount held in escrow at December 31, 2017 for the Black Diamond Acquisition.

⁽²⁾  Restricted cash represents the amount held as collateral at December 31, 2018 for certain of our letters of credit.

Revenue Recognition We generate revenues by charging fees on a per unit basis for gathering crude oil and natural gas, delivering and storing fresh water, and collecting, cleaning and disposing of produced water. Also, we purchase crude oil from producers and sell crude oil to customers at various delivery points on our gathering systems. We adopted ASC 606 on January 1, 2018, using the modified retrospective method. Under ASC 606, performance obligations are the unit of account and generally represent distinct goods or services that are promised to customers. The adoption of ASC 606 did not have an impact on the recognition, measurement and presentation of our revenues and expenses. See Note 10. Segment Information for disaggregation of revenue by reportable segment.

Performance Obligations For gathering crude oil and natural gas, treating crude oil, delivering and storing fresh water, and collecting, cleaning and disposing of produced water, our performance obligations are satisfied over time using volumes delivered to measure progress. We record revenue related to the volumes delivered at the contract price at the time of delivery.

We began generating revenue from crude oil sales during first quarter 2018 upon closing of the Black Diamond Acquisition. An affiliate of Black Diamond engages in the purchase and sale of crude oil. For our crude oil sales, each unit sold is generally considered a distinct good and the related performance obligation is generally satisfied at a point in time (i.e. at the time control of the crude oil is transferred to the customer). We recognize revenue from the sale of crude oil when our contracted performance obligation to deliver crude oil is satisfied and control of the crude oil is transferred to the customer. This usually occurs when the crude oil is delivered to the location specified in the contract and the title and risks of rewards and ownership are transferred to the customer.

Transaction Price Allocated to Remaining Performance Obligations Revenues expected to be recognized from certain performance obligations that are unsatisfied as of December 31, 2018, are reflected in the following table. We have utilized the practical expedients in ASC 606, which state that we are not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation or the transaction price allocated to remaining performance obligations if the performance obligation is part of an agreement that has an original expected duration of one year or less.

(in thousands)	December 31, 2018
2019	$	29,851
2020	36,817
2021	37,635
Total	$	104,303

Contract Balances Under our revenue agreements, we invoice customers after our performance obligations have been satisfied, at which point payment is unconditional. As such, our revenue agreements do not give rise to contract assets or liabilities under ASC 606.

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The following is a summary of our types of revenue agreements:

Crude Oil Gathering Under our crude oil gathering agreements, we receive a volumetric fee per barrel (Bbl) for the crude oil gathering services we provide.

Natural Gas Gathering Under our natural gas gathering agreements, we receive a fee per the contracted unit of measure for the natural gas gathering services we provide.

Natural Gas Compression Under our natural gas compression agreements, we receive a volumetric fee per thousand cubic feet (Mcf) for the natural gas compression services we provide.

Produced Water Services Under our produced water services agreements, we receive a fee for collecting, cleaning or otherwise disposing of water produced from operating crude oil and natural gas wells in the dedication area. The fee is comprised of a volumetric component for services we provide directly and a pass through component for services we provide through contracts with third parties.

Fresh Water Services Under our fresh water services agreements, we receive a fee for delivering fresh water. The fee is comprised of a volumetric component for services we provide directly and a pass through component for services we provide through contracts with third parties. The cost of storing the fresh water is included in the delivery fee.

Crude Oil Treating Under our crude oil treating agreements, we receive a monthly fee for the crude oil treating services we provide based on each well operated by Noble that is producing in paying quantities that is not connected to our crude oil gathering systems during such month.

Crude Oil Purchase and Sale Under our commodity purchase and sale agreements, we purchase crude oil from producers and sell crude oil to customers at various delivery points on our gathering systems. For purchase and sale transactions with the same counterparty, the purchase and sale is settled at the contractual price index on a net basis. We account for these transactions on a net basis, in accordance with ASC 845, Non-Monetary Exchanges. We record the residual fee as gathering revenue in our consolidated statements of operations. For purchase and sale transactions with different counterparties, we purchase the crude oil at market-based prices and sell the crude oil to a different counterparty at market-based prices. Market-based pricing is based on the price index applicable for the location of the sale. We account for these transactions on a gross basis.

Note 3. Acquisition

On January 31, 2018, Black Diamond completed the Black Diamond Acquisition for approximately $638.5 million in cash. Noble Member and Greenfield Member each funded its share of the purchase price, approximately $319.9 million and $318.6 million, respectively, through contributions to Black Diamond. Noble Member funded its share of the purchase price through a combination of cash on hand and borrowings under its revolving credit facility. See Note 8. Long-Term Debt.

In addition to the payment to the Seller, Black Diamond, through an additional contribution from Greenfield Member, paid PDC Energy, Inc. (PDC Energy) approximately $24.1 million to expand PDC Energy’s acreage dedication as well as extend the duration of the acreage dedication by five years. In accordance with the limited liability company agreement of Black Diamond, Noble Member is to receive a 54.4% equity ownership interest in Black Diamond and Greenfield Member is to receive a 45.6% equity ownership interest in Black Diamond. Noble Member’s agreed equity ownership interest includes a 4.4% equity ownership interest promote which will vest only after Noble Member is allocated an amount of gross revenue equal to the contributions by Greenfield Member in excess of their agreed equity ownership interest.

We serve as the operator of the Black Diamond system. We acquired a large-scale integrated gathering system located in the DJ Basin with approximately 160 miles of pipeline in operation and delivery capacity of approximately 300 MBbl/d as well as approximately 141,000 dedicated acres from six customers under fixed-fee arrangements.

In connection with the Black Diamond Acquisition, we have incurred acquisition and integration costs of $6.8 million during the year ended December 31, 2018. Our acquisition and integration costs include consulting, advisory, legal, transition services and other fees. All acquisition and integration costs were expensed and are included in general and administrative expense in our consolidated statements of operations.

Purchase Price Allocation The transaction has been accounted for as a business combination, using the acquisition method. The following table represents the final allocation of the total Black Diamond Acquisition purchase price to the assets acquired and the liabilities assumed based on the fair value at the acquisition date, with any excess of the purchase price over the estimated fair value of the identifiable net assets acquired recorded as goodwill.

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The following table sets forth our purchase price allocation:

(in thousands)
Cash Consideration	$	638,266
PDC Energy Payment	24,120
Current Liabilities Assumed	18,259
Total Purchase Price and Liabilities Assumed	$	680,645
Cash and Restricted Cash	$	12,518
Accounts Receivable	10,661
Other Current Assets	2,206
Property, Plant and Equipment	205,766
Intangible Assets  (1)	339,760
Fair Value of Identifiable Assets	570,911
Implied Goodwill (2)	109,734
Total Asset Value	$	680,645

⁽¹⁾  See Note 6. Intangible Assets.

⁽²⁾  Based upon the purchase price allocation, we have recognized $109.7 million of goodwill, all of which is assigned to the Black Diamond reporting unit within the Gathering Systems reportable segment. As a result of the acquisition, we expect to realize certain synergies which may result from our operation of the Black Diamond system.

The results of operations attributable to Black Diamond are included in our consolidated statements of operations beginning on February 1, 2018. Revenues of $181.2 million and pre-tax net loss of $11.5 million from Black Diamond were generated from February 1, 2018 to December 31, 2018.

Pro Forma Results The following pro forma consolidated financial information was derived from the historical financial statements of the Partnership and Saddle Butte and gives effect to the acquisition as if it had occurred on January 1, 2017. The pro forma results of operations do not include any cost savings or other synergies that may result from the Black Diamond Acquisition or any estimated costs that have been or will be incurred by us to integrate the acquired assets. The pro forma consolidated financial information has been included for comparative purposes and is not necessarily indicative of the results that might have actually occurred had the acquisition taken place on January 1, 2017; furthermore, the financial information is not intended to be a projection of future results.

	Year Ended December 31,
(in thousands, except per unit amounts)	2018		2017
Revenues	$	506,032	$	355,159
Net Income	186,391		138,940
Net Income Attributable to Noble Midstream Partners LP	$	161,068	$	123,375
Net Income Attributable to Limited Partners Per Limited Partner Common and Subordinated Unit
Basic	$	3.92	$	3.59
Diluted	$	3.92	$	3.59

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Note 4. Transactions with Affiliates

Revenues We derive a substantial portion of our revenues from commercial agreements with Noble. Revenues generated from commercial agreements with Noble and its affiliates consist of the following:

	Year Ended December 31,
(in thousands)	2018		2017		2016
Crude Oil, Natural Gas and Produced Water Gathering	$	207,920	$	142,864	$	94,160
Fresh Water Delivery	69,266		75,860		60,001
Other	3,976		5,677		6,563
Total Midstream Services — Affiliate	$	281,162	$	224,401	$	160,724

Expenses General and administrative expense consists of the following:

	Year Ended December 31,
(in thousands)	2018		2017		2016
General and Administrative Expense — Affiliate	$	7,493	$	7,323	$	6,984
General and Administrative Expense — Third Party	16,757		6,073		2,930
Total General and Administrative Expense	$	24,250	$	13,396	$	9,914

Asset Sale and Purchases — Affiliate During third quarter 2016, we sold certain equipment to Noble, at cost, and received proceeds of $1.9 million. No gain or loss was recognized for the transaction. During fourth quarter 2016, we purchased certain equipment from Noble, at market value, for approximately $0.9 million.

Agreements with Noble We have entered into various agreements with Noble, as summarized below:

Commercial Agreements Our commercial agreements with Noble provide for fees based on the type and scope of the midstream services we provide and the midstream system we use to provide our services, as follows:

• Crude Oil Gathering Agreement - Under the applicable crude oil gathering agreement, we receive a volumetric fee per barrel (Bbl) for the crude oil gathering services we provide.

• Natural Gas Gathering Agreement - Under the natural gas gathering agreement, we receive a volumetric fee per million British Thermal Units (MMBtu) for the natural gas gathering services we provide.

• Produced Water Services Agreement - Under the applicable produced water services agreement, we receive a fee for collecting, cleaning or otherwise disposing of water produced from operating crude oil and natural gas wells in the dedication area. The fee is comprised of a volumetric component for services we provide directly and a pass through component for services we provide through contracts with third parties.

• Fresh Water Services Agreement - Under the applicable fresh water services agreement, we receive a fee for delivering fresh water. The fee is comprised of a volumetric component for services we provide directly and a pass through component for services we provide through contracts with third parties. The cost of storing the fresh water is included in the delivery fee. 

• Crude Oil Treating Agreement - Under the crude oil treating agreement, we receive a monthly fee for the crude oil treating services we provide based on each well operated by Noble that is producing in paying quantities that is not connected to our crude oil gathering systems during such month.

• Natural Gas Compression Agreement - Under the applicable natural gas compression agreement, we receive a volumetric fee per thousand cubic feet (Mcf) for the natural gas compression services we provide.

Under each of these commercial agreements, the volumetric fees we charge Noble (other than pass through fees) are automatically increased each calendar year by 2.5%, expect for Blanco River DevCo LP Natural Gas Gathering. The volumetric fee for Blanco Gas Gathering is automatically increased by the Consumer Price Index (CPI) for the previous year; provided, however, that no such increase may exceed 2.5% for any given year. In addition, 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, which in effect allows Noble to unilaterally exercise control over the decision of whether to change the fee.

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In accordance with our commercial agreements with Noble, we provide midstream services through the use of our midstream assets. We have determined that the structure of our commercial agreements conveys to Noble the right to use our midstream assets. Revenues generated from the commercial agreements are recorded within Midstream Services - Affiliate in our consolidated statement of operations. We believe recording within Midstream Services - Affiliate reflects the nature of the commercial agreement, is representative of the revenues generated by the midstream industry and provides our investors with the information necessary to evaluate our operations.

Omnibus Agreement Our omnibus agreement with Noble provides for:

• our payment of an annual general and administrative fee, initially in the amount of $6.9 million (prorated for the first year of service), for the provision of certain services by Noble and its affiliates, which fee cannot be increased until after the third anniversary of the IPO with annual redetermination thereafter;

• our right of first refusal on existing Noble and future Noble acquired assets and the right to provide certain services, including the right to provide crude oil gathering, natural gas gathering and processing, and water services on certain acreage owned, or to be acquired, by Noble;

• our right of first offer to acquire Noble’s retained interests in each of the DevCos; 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 its assets that occur after the closing of the IPO and for environmental liabilities related to our assets to the extent Noble is not required to indemnify us.

Operational Services Agreement Our Operational Services and Secondment Agreement (Operational Services Agreement) with Noble provides for:

• secondment by Noble of certain operational, construction, design and management employees and contractors to our general partner, us and our subsidiaries to provide management, maintenance and operational functions with respect to our assets. These functions include performing the activities and day-to-day management of the business pursuant to certain commercial agreements listed in the Operational Services Agreement, and designing, building, constructing and otherwise installing the infrastructure required by such agreements;

• reimbursement by us to Noble of the cost of the seconded employees and contractors, including their wages and benefits, based on the percentage of the employee’s or contractor’s time spent working for us; and

• an initial term of 15 years and automatic extensions for successive renewal terms of one year each, unless terminated by either party.

Note 5. Property, Plant and Equipment

Property, plant and equipment, at cost, is as follows:

(in thousands)	December 31, 2018			December 31, 2017
Crude Oil, Natural Gas and Produced Water Gathering Systems and Facilities	$	1,199,679		$	451,275
Fresh Water Delivery System (1)	78,820			76,745
Crude Oil Treating Facilities	20,027			20,099
Construction-in-Progress (2)	202,083			157,920
Total Property, Plant and Equipment, at Cost	1,500,609			706,039
Accumulated Depreciation and Amortization	(79,357		)	(44,271		)
Property, Plant and Equipment, Net	$	1,421,252		$	661,768

⁽¹⁾  Fresh water delivery system assets at December 31, 2018 and December 31, 2017 include $5 million related to a leased pond accounted for as a capital lease. See Note 15. Commitments and Contingencies.

⁽²⁾  Construction-in-progress at December 31, 2018 primarily includes $147.1 million in gathering system projects, $21.6 million in fresh water delivery system projects and $32.8 million in equipment for use in future projects. Construction-in-progress at December 31, 2017 primarily includes $157.4 million in gathering system projects and $0.5 million in fresh water delivery system projects.

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Note 6. Intangible Assets

Our intangible assets as of December 31, 2018 are comprised of customer contracts and relationships from the Black Diamond Acquisition and were recorded under the acquisition method of accounting at their estimated fair values at the date of acquisition. The customer contracts we acquired are long-term, fixed-fee contracts for the purchase and sale of crude oil. See Note 2. Summary of Significant Accounting Policies and Basis of Presentation for further discussion of our crude oil purchase and sale revenue agreements. Fair value was calculated using the multi-period excess earnings method under the income approach for the existing customers. This valuation method is based on first forecasting gross profit for the existing customers and then applying expected attrition rates. The operating cash flows were calculated by determining the costs required to generate gross profit from the existing customers. The key assumptions include overall gross profit growth, attrition rate of existing customers over time and the discount rate. As the fair value is based on inputs that are not observable in the market, these represent Level 3 inputs.

We utilize the straight-line method of amortization for intangible assets with finite lives. The amortization period is reflective of the benefit pattern in which the estimated economic benefit is expected to be received over the estimated useful life of the intangible asset. The estimated economic benefit was determined by assessing the life of the assets related to the contracts and relationships, likelihood of renewals, competitive factors, regulatory or legal provisions and maintenance costs.

Our intangible assets are as follows:

		December 31, 2018
	Useful Life	Intangible Assets, Gross (in thousands)		Accumulated Amortization (in thousands)		Intangible Assets, Net (in thousands)
Customer Contracts and Relationships	7-13 years (1)	$	339,760	$	29,558	$	310,202

⁽¹⁾  The weighted average useful life of our customer contracts and customer relationships is approximately 11 years.

Estimated future amortization expense related to the intangible assets at December 31, 2018 is as follows:

(in thousands)	December 31, 2018
2019	$	32,301
2020	32,390
2021	32,301
2022	32,301
2023	32,301
Thereafter	148,608
Total	$	310,202

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Note 7. Investments

The following table presents our investments at the dates indicated:

(in thousands)	December 31, 2018		December 31, 2017
Advantage Joint Venture (1)	$	72,944	$	70,283
White Cliffs Interest	9,373		10,178
Total Investments	$	82,317	$	80,461

⁽¹⁾  We capitalized $1.7 million in acquisition related expenses that are included in the basis of the investment. As of December 31, 2018, $1.6 million in acquisition related expenses remains unamortized.

The following table presents our investment income for the periods indicated:

	Year Ended December 31,
(in thousands)	2018		2017		2016
Advantage Joint Venture (1)	$	11,880	$	1,779	$	—
White Cliffs Interest	3,687		4,088		4,526
Other (2)	722		467		—
Total Investment Income	$	16,289	$	6,334	$	4,526

⁽¹⁾  Includes the amortization of acquisition related expenses. As we completed the Advantage acquisition on April 3, 2017, the year-to-date results are for the period beginning on April 3, 2017 and ending on December 31, 2017.

⁽²⁾  Represents income associated with our fee for serving as the operator of the Advantage Joint Venture. The fee totals approximately $0.7 million per year.

Note 8. Long-Term Debt

Long-term debt as of December 31, 2018 and December 31, 2017 was as follows:

	December 31, 2018					December 31, 2017
(in thousands, except percentages)	Debt			Interest Rate		Debt		Interest Rate
Revolving Credit Facility, due March 9, 2023	$	60,000		3.67	%	$	85,000	2.75	%
Term Loan Credit Facility, due July 31, 2021	500,000			3.42	%	—		—	%
Long-Term Debt, Gross	560,000					85,000
Term Loan Credit Facility Unamortized Debt Issuance Costs	(979		)			—
Long-Term Debt	$	559,021				$	85,000

Revolving Credit Facility We maintain a revolving credit facility to fund working capital and to finance acquisitions and expansion capital expenditures. On January 31, 2018, in connection with the closing of the Black Diamond Acquisition, we entered into an amendment to increase the capacity on our revolving credit facility from $350 million to $530 million. On March 9, 2018, we entered into an additional amendment to extend the maturity of the facility to March 9, 2023 and increase the borrowing capacity to $800 million. The borrowing capacity on our revolving credit facility may be increased by up to an additional $350 million subject to certain conditions including compliance with the covenants contained in the credit agreement and requisite commitments from existing or new lenders.

During the year ended December 31, 2018, borrowings under our revolving credit facility were primarily used to fund portions of our construction activities and the Black Diamond Acquisition. During third quarter 2018, we repaid $480 million on our revolving credit facility through the issuance of our term loan credit facility. See Term Loan Credit Facility below.

During the year ended December 31, 2017, borrowings under our revolving credit facility were primarily used to fund portions of our construction activities, the Advantage acquisition, and the cash consideration for the Contributed Assets.

Borrowings under the revolving credit facility bear interest at a rate equal to an applicable margin plus, at our option, either (a) in the case of base rate borrowings, a rate equal to the highest of (1) the prime rate, (2) the greater of the federal funds rate or the overnight bank funding rate, plus 0.5% and (3) the LIBOR for an interest period of one month plus 1.0%; or (b) in the case of LIBOR borrowings, the offered rate per annum for deposits of dollars for the applicable interest period.

The unused portion of the revolving credit facility is subject to a commitment fee. As of December 31, 2017 and December 31, 2018, the commitment fee rate was 0.2%. Unamortized debt issuance costs totaled $1.4 million and $2.7 million as of

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December 31, 2017 and December 31, 2018, respectively, and are recorded within other noncurrent assets in our consolidated balance sheets.

The revolving credit facility requires us to comply with certain financial covenants as of the end of each fiscal quarter. We were in compliance with such covenants as of December 31, 2018. Certain lenders that are a party to the credit agreement have in the past performed, and may in the future from time to time perform, investment banking, financial advisory, lending or commercial banking services for us for which they have received, and may in the future receive, customary compensation and reimbursement of expenses.

Term Loan Credit Facility On July 31, 2018, we entered into a three year senior unsecured term loan credit facility that permits aggregate borrowings of up to $500 million. Proceeds from the term loan credit facility were primarily used to repay a portion of the outstanding borrowings under our revolving credit facility and pay fees and expenses in connection with the term loan credit facility transactions.

Borrowings under the term loan credit facility bear interest at a rate equal to, at our option, either (1) a base rate plus an applicable margin between 0.00% and 0.50% per annum or (2) a Eurodollar rate plus an applicable margin between 1.00% and 1.50% per annum.

The term loan credit facility contains customary representations and warranties, affirmative and negative covenants, and events of default that are substantially the same as those contained in our revolving credit facility, including the requirement to comply with certain financial covenants as of the end of each fiscal quarter. We were in compliance with the term loan credit facility covenants as of December 31, 2018. Upon the occurrence and during the continuation of an event of default under the term loan credit facility, the lenders may declare all amounts outstanding under the term loan credit facility to be immediately due and payable and exercise other remedies as provided by applicable law.

Note 9. Asset Retirement Obligations

AROs consist of estimated costs of dismantlement, removal, site reclamation and similar activities associated with our infrastructure assets. Changes in AROs are as follows:

	Year Ended December 31,
(in thousands)	2018		2017
Asset Retirement Obligations, Beginning Balance	$	10,416	$	5,415
Liabilities Incurred	5,582		4,828
Revision of Estimate	662		(151		)
Accretion Expense (1)	670		324
Asset Retirement Obligations, Ending Balance	$	17,330	$	10,416

⁽¹⁾  Accretion expense is included in depreciation and amortization expense in the consolidated statements of operations.

Liabilities incurred in 2018 were primarily related to the completion of the CGFs in the Delaware Basin. During 2018, we completed the Coronado, Collier and Billy Miner Train II CGFs. Revisions of estimates during 2018 were primarily related to an increase in estimated costs associated with the retirement of our CGFs.

With respect to property, plant and equipment acquired in the Black Diamond Acquisition, it is our practice and current intent to maintain these assets and continue to make improvements as warranted. As a result, we believe that these assets have indeterminate lives for purposes of estimating AROs because dates or ranges of dates upon which we would retire these assets cannot reasonably be estimated at this time; therefore, no AROs have been recorded for these assets as of December 31, 2018.

Liabilities incurred in 2017 were primarily related to our Billy Miner I and Jesse James CGFs in the Delaware Basin as well as the expansion of our gathering systems in the Delaware Basin and Greeley Crescent IDP area.

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Note 10. Segment Information

Our operations are located in the U.S. and are organized into the following reportable segments: Gathering Systems (primarily includes crude oil, natural gas and produced water gathering and crude oil sales), Fresh Water Delivery, and Investments and Other. We often refer to the services of our Gathering Systems and Fresh Water Delivery reportable segments collectively as our midstream services. Our reportable segments comprise the structure used to make key operating decisions and assess performance.

Summarized financial information concerning our reportable segments is as follows:

(in thousands)	Gathering Systems(1)		Fresh Water Delivery(1)		Investments and Other (1) (2)			Consolidated
Year Ended December 31, 2018
Midstream Services — Affiliate	$	211,896	$	69,266	$	—		$	281,162
Midstream Services — Third Party	53,523		19,345		—			72,868
Crude Oil Sales — Third Party	141,490		—		—			141,490
Total Midstream Services Revenues	406,909		88,611		—			495,520
Cost of Crude Oil Sales	136,368		—		—			136,368
Direct Operating Expense	68,478		14,269		1,735			84,482
Depreciation and Amortization	63,055		2,259		—			65,314
Income (Loss) Before Income Taxes	137,203		72,083		(20,189		)	189,097
Year Ended December 31, 2017
Midstream Services — Affiliate	$	148,541	$	75,860	$	—		$	224,401
Midstream Services — Third Party	3,971		10,909		—			14,880
Total Midstream Services Revenues	152,512		86,769		—			239,281
Direct Operating Expense	37,138		16,011		858			54,007
Depreciation and Amortization	10,687		2,266		—			12,953
Income (Loss) Before Income Taxes	104,687		68,492		(9,523		)	163,656
Year Ended December 31, 2016
Midstream Services — Affiliate	$	100,723	$	60,001	$	—		$	160,724
Direct Operating Expense	14,443		14,390		274			29,107
Depreciation and Amortization	7,361		1,705		—			9,066
Income (Loss) Before Income Taxes	78,919		43,906		(9,035		)	113,790
December 31, 2018
Intangible Assets, Net	$	310,202	$	—	$	—		$	310,202
Goodwill	109,734		—		—			109,734
Total Assets	1,804,100		96,280		97,537			1,997,917
Additions to Long-Lived Assets	735,425		23,018		555			758,998
December 31, 2017
Total Assets	$	593,590	$	68,178	$	167,990		$	829,758
Additions to Long-Lived Assets	373,857		16,469		—			390,326
December 31, 2016
Total Assets	$	224,861	$	54,542	$	89,956		$	369,359
Additions to Long-Lived Assets	30,020		2,564		—			32,584

⁽¹⁾  A substantial portion of the financial statement activity associated with our DevCos is captured within the Gathering Systems and Fresh Water Delivery reportable segments. Although our investment in the Advantage Joint Venture is owned by Trinity River DevCo LLC, all financial statement activity associated with our investment is captured within the Investments and Other reportable segment. As our DevCos represent VIEs, see the above reportable segments for our VIEs impact to the consolidated financial statements.

⁽²⁾  The Investments and Other segment includes our investments in the Advantage Joint Venture and White Cliffs Interest as well as all general Partnership activity not attributable to our DevCos.

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Table of Contents	Noble Midstream Partners LP
Index to Financial Statements	Notes to Consolidated Financial Statements

Note 11. Unit-Based Compensation

The Noble Midstream Partners LP 2016 Long-Term Incentive Plan (the LTIP) provides for the grant, at the discretion of the board of directors of our general partner, 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 limits the number of units that may be delivered pursuant to vested awards to 1,860,000 Common Units, subject to proportionate adjustment in the event of unit splits and similar events. Common units subject to awards that are canceled, forfeited, withheld to satisfy exercise prices or tax withholding obligations or otherwise terminated without delivery of Common Units will be available for delivery pursuant to other awards. As of December 31, 2018, 1,763,411 Common Units are available for future grant under the LTIP.

Restricted unit activity for the year ended December 31, 2018 was as follows:

	Number of Units		Weighted Average Award Date Fair Value
Awarded and Unvested Units at December 31, 2017	34,704		$	45.10
Awarded	54,017		54.80
Vested	(11,049	)	44.62
Forfeited	(6,253	)	51.92
Awarded and Unvested Units at December 31, 2018	71,419		$	51.92

As of December 31, 2018, $2.2 million of compensation cost related to all of our unvested restricted units awarded under the LTIP remained to be recognized. The cost is expected to be recognized over a weighted-average period of 1.4 years.

Note 12. Partnership Distributions

Our partnership agreement requires that, within 45 days after the end of each quarter, we distribute all of our available cash to unitholders of record on the applicable record date. The following table details the distributions paid in respect of the periods presented below:

					Distributions
					Limited Partners
Period	Record Date	Distribution Date	Distribution per Limited Partner Unit		Common Unitholders(1)		Subordinated Unitholders		Holder of IDRs		Total
Q4 2016(2)	February 6, 2017	February 14, 2017	$	0.4333	$	6,891	$	6,891	$	—	$	13,782
Q1 2017	May 8, 2017	May 16, 2017	$	0.4108	$	6,533	$	6,533	$	—	$	13,066
Q2 2017	August 7, 2017	August 14, 2017	$	0.4457	$	8,909	$	7,088	$	92	$	16,089
Q3 2017	November 6, 2017	November 13, 2017	$	0.4665	$	9,330	$	7,418	$	223	$	16,971
Q4 2017	February 5, 2018	February 12, 2018	$	0.4883	$	11,566	$	7,765	$	520	$	19,851
Q1 2018	May 7, 2018	May 14, 2018	$	0.5110	$	12,103	$	8,126	$	819	$	21,048
Q2 2018	August 6, 2018	August 13, 2018	$	0.5348	$	12,668	$	8,504	$	1,134	$	22,306
Q3 2018	November 5, 2018	November 13, 2018	$	0.5597	$	13,258	$	8,901	$	1,462	$	23,621

⁽¹⁾  Distributions to common unitholders does not include distribution equivalent rights on units that vested under the LTIP.

⁽²⁾  The distribution for the fourth quarter 2016 is comprised of $0.3925 per unit for the fourth quarter 2016 and $0.0408 per unit for the 10-day period beginning on the closing of the IPO on September 20, 2016 and ending on September 30, 2016.

Incentive Distribution Rights Noble currently holds IDRs that entitle it to receive increasing percentages, up to a maximum of 50%, of the available cash we distribute from operating surplus in excess of $0.4313 per unit per quarter. The maximum distribution of 50% does not include any distributions that Noble may receive on Common Units or Subordinated Units that it owns.

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Table of Contents	Noble Midstream Partners LP
Index to Financial Statements	Notes to Consolidated Financial Statements

Cash Distributions On January 24, 2019, the board of directors of our general partner declared a quarterly cash distribution of $0.5858 per limited partner unit. The distribution was paid on February 11, 2019, to unitholders of record on February 4, 2019. Also on February 11, 2019, a cash distribution of $2.4 million was paid to Noble related to its IDRs, based upon the level of distribution paid per Common and Subordinated unit.

Note 13. Net Income Per Limited Partner Unit

The Partnership’s net income is attributed to limited partners, in accordance with their respective ownership percentages, and when applicable, giving effect to incentive distributions paid to Noble, the holder of our IDRs. The Common and Subordinated unitholders represent an aggregate 100% limited partner interest in us. Pursuant to our partnership agreement, to the extent that the quarterly distributions exceed certain target levels, Noble, as the holder of our IDRs, is entitled to receive certain incentive distributions that will result in more net income proportionately being allocated to Noble than to the holders of Common and Subordinated Units.

Because we have more than one class of participating securities, we use the two-class method when calculating the net income per unit applicable to limited partners. The classes of participating securities include Common Units, Subordinated Units and IDRs.

Basic and diluted net income per limited partner Common and Subordinated Unit is computed by dividing the respective limited partners’ interest in net income for the period by the weighted-average number of Common and Subordinated Units outstanding for the period. Diluted net income per limited partner Common and Subordinated Unit reflects the potential dilution that could occur if agreements to issue Common Units, such as awards under the LTIP, were settled or converted into Common Units. When it is determined that potential Common Units resulting from an award should be included in the diluted net income per limited partner Common and Subordinated Unit calculation, the impact is reflected by applying the treasury stock method. 

Our calculation of net income per limited partner Common and Subordinated Unit is as follows:

	Year Ended December 31,
(in thousands)	2018		2017		2016
Net Income Attributable to Noble Midstream Partners LP	$	162,734	$	140,572	$	28,458
Less: Net Income Attributable to Incentive Distribution Rights	5,836		835		—
Net Income Attributable to Limited Partners	$	156,898	$	139,737	$	28,458
Net Income Allocable to Common Units	$	93,875	$	75,076	$	14,229
Net Income Allocable to Subordinated Units	63,023		64,661		14,229
Net Income Attributable to Limited Partners	$	156,898	$	139,737	$	28,458
Net Income Attributable to Limited Partners Per Limited Partner Common and Subordinated Unit
Basic	$	3.96	$	4.10	$	0.89
Diluted	$	3.96	$	4.10	$	0.89
Weighted Average Limited Partner Units Outstanding — Basic
Common Units	23,686		18,192		15,903
Subordinated Units	15,903		15,903		15,903
Weighted Average Limited Partner Units Outstanding — Diluted
Common Units	23,701		18,204		15,903
Subordinated Units	15,903		15,903		15,903
Antidilutive Restricted Units	24		4		—

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Table of Contents	Noble Midstream Partners LP
Index to Financial Statements	Notes to Consolidated Financial Statements

Note 14. Income Taxes

We are not a taxable entity for U.S. federal income tax purposes or for the majority of states that impose an income tax. Taxes are generally borne by our partners through the allocation of taxable income, and accordingly for the periods subsequent to the IPO, we do not record deferred taxes related to the aggregate difference in the basis of our assets for financial and tax reporting purposes.

On December 22, 2017, the US Congress enacted Tax Reform Legislation, which made significant changes to US federal income tax law, including Section 163(j) interest expense limitation rules which have no current impact to the Partnership, but could increase taxable income flowing through to our partners in future years.

We recorded a de minimis state tax provision for the years ended December 31, 2018 and December 31, 2017 associated with a Texas margin tax. The income tax provision for the year ended December 31, 2016 consists of the following:

(in thousands)	Year Ended December 31, 2016
Current	$	15,450
Deferred	12,838
Total Income Tax Provision	$	28,288
Effective Tax Rate (1)	24.9		%

⁽¹⁾  The effective tax rate for the period beginning on January 1, 2016 and ending on the IPO date was 38.1%.

See Note 2. Summary of Significant Accounting Policies and Basis of Presentation above for discussion of elimination of current and deferred tax liabilities prior to the IPO.

Note 15. Commitments and Contingencies

Legal Proceedings  We may become involved in various legal proceedings in the ordinary course of business. These proceedings would be subject to the uncertainties inherent in any litigation, and we will regularly assess the need for accounting recognition or disclosure of these contingencies. We will defend ourselves vigorously in all such matters.

For periods prior to the IPO, 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. As of December 31, 2018 and December 31, 2017, we did not have accrued liabilities for any legal contingencies related to us.

Based on currently available information, we believe it is unlikely that the outcome of known matters would have a material adverse impact on our combined financial condition, results of operations or cash flows.

Omnibus Agreement Our omnibus agreement with Noble contractually requires us to pay a fixed annual fee of $6.9 million (prorated for the first year of service) to Noble for certain administrative and operational support services being provided to us. The omnibus agreement generally remains in full force and effect so long as Noble controls our general partner. See Note 4. Transactions with Affiliates.

Capital Lease During third quarter 2016, we leased a pond for use in our fresh water delivery system. We are accounting for the lease as a capital lease. The discounted present value of future minimum lease payments totals approximately $3.2 million as of December 31, 2018.

Crude Oil Purchase Commitments An affiliate of Black Diamond enters into agreements to purchase crude oil from producers at market-based prices. The agreements do not contain provisions regarding fixed or minimum quantities of crude oil to be purchased.

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Table of Contents	Noble Midstream Partners LP
Index to Financial Statements	Notes to Consolidated Financial Statements

Minimum commitments as of December 31, 2018 are as follows:

(in thousands)	Omnibus Fee (1)		Future Minimum Capital Lease Payments		Future Minimum Operating Lease Payments		Purchase Obligations (2)		Transportation Fees		Surface Lease Obligations
2019	$	6,850	$	3,231	$	1,733	$	3,637	$	1,825	$	129
2020	—		—		—		—		605		129
2021	—		—		—		—		—		130
2022	—		—		—		—		—		89
2023	—		—		—		—		—		89
2024 and Beyond	—		—		—		—		—		2,180
Total	$	6,850	$	3,231	$	1,733	$	3,637	$	2,430	$	2,746

⁽¹⁾  Annual general and administrative fee we pay to Noble for certain administrative and operational support services being provided to us. The annual general and administrative fee cannot be increased until after the third anniversary of the IPO and will be redetermined annually thereafter.

⁽²⁾  Purchase obligations represent contractual agreements to purchase goods or services that are enforceable, are legally binding and specify all significant terms, including fixed and minimum quantities to be purchased; fixed, minimum or variable price provisions; and the approximate timing of the transaction.

Note 16. Subsequent Events

EPIC Equity Interests On August 2, 2018, Noble assigned its option with EPIC Midstream Holdings, LP (EPIC) to acquire a 15% equity interest in the EPIC Y-Grade Pipeline to the Partnership. On January 31, 2019, Noble assigned its option to acquire a 30% equity interest in the EPIC Crude Oil Pipeline to the Partnership. Both options were set to expire February 1, 2019.

On January 31, 2019, the Partnership exercised and closed its option with EPIC to acquire the equity interest in the EPIC Y-Grade Pipeline. At closing, we made cash contributions of approximately $103 million.

Also on January 31, 2019, the Partnership exercised its option to acquire the equity interest in the EPIC Crude Oil Pipeline. Closing of the Partnership’s equity interest in the EPIC Crude Oil Pipeline is expected to occur later in first quarter 2019, subject to certain conditions precedent.

Delaware Crossing Joint Venture On October 2, 2018, we entered into a non-binding letter of intent with Salt Creek Midstream LLC (Salt Creek) to form a 50/50 joint venture to construct a crude oil pipeline system with a capacity of 160 MBbl/d in the Delaware Basin. On February 7, 2019, we executed definitive agreements and completed the formation of Delaware Crossing LLC (Delaware Crossing Joint Venture). As Salt Creek has commenced construction of the pipeline prior to formation, we made capital contributions of approximately $38 million at closing.

Revolving Credit Facility We utilized proceeds from our revolving credit facility to fund our contributions in connection with the closing of the EPIC Y-Grade equity interest and Delaware Crossing Joint Venture. As of February 15, 2019, $260 million was outstanding under our revolving credit facility.

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Table of Contents	Noble Midstream Partners LP
Index to Financial Statements	Supplemental Quarterly Financial Information
	(Unaudited)

Supplemental quarterly financial information is as follows:

(in thousands except per share amounts)	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
Year Ended December 31, 2018
Total Revenues	$	97,733	$	121,971	$	139,163	$	136,653
Operating Income	37,375		42,215		48,249		55,461
Income Before Income Taxes	39,210		44,625		48,609		56,653
Net Income	39,136		44,442		48,703		56,595
Net Income Attributable to Limited Partners	38,542		35,450		43,155		39,751
Net Income Attributable to Limited Partners Per Limited Partner Common and Subordinated Unit
Basic	$	0.97	$	0.9	$	1.09	$	1.00
Diluted	0.97		0.9		1.09		1.00
Year Ended December 31, 2017
Total Revenues	$	50,314	$	57,783	$	63,111	$	68,073
Operating Income	33,722		37,566		42,750		44,887
Income Before Income Taxes	34,520		39,107		43,789		46,240
Net Income	34,520		39,107		43,756		46,253
Net Income Attributable to Limited Partners	24,342		31,500		41,447		42,448
Net Income Attributable to Limited Partners Per Limited Partner Common and Subordinated Unit
Basic	$	0.77	$	0.98	$	1.15	$	1.16
Diluted	0.77		0.98		1.15		1.16

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Item 9.  Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

Item 9A. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed by us in the reports we file or furnish to the SEC under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified by the SEC’s rules and forms, and that information is accumulated and communicated to management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.

Our principal executive officer and principal financial officer have evaluated the effectiveness of our “disclosure controls and procedures,” as such term is defined in Rule 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended, as of the end of the period covered by this Annual Report. Based upon their evaluation, they have concluded that our disclosure controls and procedures were effective and provide an effective means to ensure that information required to be disclosed in the reports that we file or furnish under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified by the SEC’s rules and forms and that information is accumulated and communicated to management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.

In designing and evaluating our disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable, and not absolute, assurance that the objectives of the control system will be met. In addition, the design of any control system is based in part upon certain assumptions about the likelihood of future events and the application of judgment in evaluating the cost-benefit relationship of possible controls and procedures. Because of these and other inherent limitations of control systems, there is only reasonable assurance that our controls will succeed in achieving their goals under all future conditions.

Management’s Annual Report on Internal Control over Financial Reporting

The management report called for by Item 308(a) of Regulation S-K is incorporated herein by reference to Management’s Report on Internal Control over Financial Reporting, included in Item 8. Financial Statements and Supplementary Data.

The independent auditor’s attestation report called for by Item 308(b) of Regulation S-K is incorporated herein by reference to Report of Independent Registered Public Accounting Firm (Internal Control Over Financial Reporting), included in Item 8. Financial Statements and Supplementary Data.

Changes in Internal Control over Financial Reporting

Our management is also responsible for establishing and maintaining adequate internal controls over financial reporting, as defined in Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934, as amended. Our internal controls were designed to provide reasonable assurance as to the reliability of our financial reporting and the preparation and presentation of the consolidated financial statements for external purposes in accordance with US GAAP.

Because of its inherent limitations, internal control over financial reporting may not detect or prevent misstatements. Projections of any evaluation of the effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Our management has assessed the effectiveness of our internal controls over financial reporting as of December 31, 2018. Based on our assessment, our internal controls over financial reporting were effective. There were no changes in internal controls over financial reporting that occurred during the most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

Item 9B.  Other Information

None.

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PART III

Item 10. Directors, Executive Officers and Corporate Governance

Management of Noble Midstream Partners LP

We are managed by the directors and executive officers of our General Partner. Our General Partner is not elected by our unitholders and will not be subject to re-election by our unitholders in the future. Noble indirectly owns all of the membership interests in our General Partner. 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.

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. While all of the employees that conduct our business are employed by our General Partner or its affiliates, in this Annual Report, we sometimes refer to these individuals as our employees.

Director Independence

As a publicly traded partnership, we qualify for, and are relying on, certain exemptions from the NYSE 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, our General Partner’s board of directors is not 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, all of whom satisfy the independence and experience standards established by the NYSE and the Exchange Act.

We have also established a standing conflicts committee, as permitted under our partnership agreement.

Committees of the Board of Directors

In addition to the audit committee and the conflicts committee, the board of directors of our General Partner may have such other committees as the board of directors shall determine from time to time.

Audit Committee

The audit committee of the board of directors of our General Partner assists 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 has 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. We have adopted an Audit Committee charter which is available on our website.

The audit committee is also 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. Ms. Hallie A. Vanderhider (Chairperson), Mr. Martin Salinas and Mr. Andrew Viens comprise the members of the audit committee. The board of directors of our General Partner determined that each of Ms. Vanderhider, Mr. Salinas and Mr. Viens satisfy the definition of audit committee financial expert for purposes of the SEC’s rules and is independent under the standards of the NYSE.

While the audit committee of the board of directors of our General Partner oversees the Partnership’s financial reporting process on behalf of the board of directors, management has the primary responsibility for the financial statements and the

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reporting process, including the systems of internal controls. In fulfilling its oversight responsibilities, the audit committee reviews and discusses with management the audited financial statements contained in this Annual Report.

Conflicts Committee

In January 2017, we established a standing conflicts committee of the board of directors of our General Partner. The board of directors of our General Partner will delegate the conflicts committee authority, from time to time, to review, in accordance with the terms of our partnership agreement, specific matters that may involve a potential conflict of interest between our General Partner or any of its affiliates (including Noble), on the one hand, and us or any of our subsidiaries or partners, on the other hand. The board of directors of our General Partner determines whether to refer a matter to the conflicts committee on a case-by-case basis.

The conflicts committee is comprised of three members of the board of directors of our General Partner. The members of the conflicts committee are Mr. Salinas (Chairperson), Ms. Vanderhider and Mr. Viens. The members of our conflicts committee may not be officers or employees of our General Partner or directors, officers, or employees of any 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.

Board Leadership Structure

Although the chief executive officer of our General Partner currently does not also serve as the chairman of the board of directors of our General Partner, 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 is defined and governed by the amended and restated limited liability company agreement of our General Partner, which permits 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 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 is 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.

Non-Management Executive Sessions and Unitholder Communications

During the fiscal year ended December 31, 2018, the non-management directors met four times in executive session. Ms. Vanderhider, as Chair of the Audit Committee, acted as presiding director in such sessions.

Unitholders and interested parties can communicate directly with non-management directors by mail in care of the General Counsel and Secretary at Noble Midstream Partners LP, 1001 Noble Energy Way, Houston, Texas 77070. Such communications should specify the intended recipient or recipients. Commercial solicitations or communications will not be forwarded.

Meetings and Other Information

During the fiscal year ended December 31, 2018, our board of directors had six meetings and our audit committee had four meetings. All directors have access to members of management, and a substantial amount of information transfer and informal communication occurs between meetings. Each of our directors attended all of the meetings of the board of directors, pricing committee and audit committee on which such director served.

Our Code of Business Conduct and Ethics, Corporate Governance Guidelines, Whistleblower Policy and Audit Committee Charter are available on our website (www.nblmidstream.com) under the Corporate Governance tab. Our Code of Business Conduct and Ethics applies to our principal executive officer, principal financial officer, principal accounting officer or controller, or persons performing similar functions. We intend to disclose any amendment to or waiver of our Code of Business Conduct and Ethics either on our website or in a current report on Form 8-K filed with the SEC.

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Directors and Executive Officers

Directors are appointed by Noble, the sole member 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 and executive officers of our General Partner as of December 31, 2018.

Name	Age	Position with Our General Partner
Terry R. Gerhart	58	Chief Executive Officer and Director
Kenneth M. Fisher	57	Chairman of the Board of Directors
Thomas H. Walker	48	Director
Brent J. Smolik	57	Director
Hallie A. Vanderhider	61	Director
Martin Salinas, Jr.	46	Director
Andrew E. Viens	64	Director
John F. Bookout, IV	32	Chief Financial Officer
Thomas W. Christensen	36	Chief Accounting Officer
John C. Nicholson	34	Chief Operating Officer
Harry R. Beaudry	48	General Counsel and Secretary

Terry R. Gerhart was appointed Chief Executive Officer and as a director of our General Partner in October 2015. Mr. Gerhart applies more than 34 years of industry experience to ensure safe, responsible delivery of midstream solutions to Noble Energy and other producers. In addition to this role, Mr. Gerhart serves as Senior Vice President, Midstream, for Noble, which he was appointed to in February 2018. At Noble, Mr. Gerhart previously served as Senior Vice President Global Operations Services from September 2015 to February 2018, Vice President Africa from April 2013 to September 2015, Vice President Eastern Mediterranean Operations from August 2011 to April 2013, and Vice President International Non-Operated Assets and Global Gas Monetization from December 2009 to August 2011. He began his career with Atlantic Richfield as a petroleum engineer holding various engineering, operations and management positions of increasing importance. He was part of the team that started the U.S. independent Vastar Resources, worked later as an executive for BP, and then with a technology based exploration start-up company before joining Noble. During his career, he has helped design, construct, operate, and manage upstream oil and gas gathering and treatment facilities, natural gas processing plants, and offshore production facilities throughout the world. We believe that Mr. Gerhart’s substantial prior experience with Noble and other companies engaged in energy-related businesses will provide the board of directors with valuable insight.

Kenneth M. Fisher was appointed as Chairman of the board of directors of our General Partner in October 2015. Mr. Fisher serves as Executive Vice President and Chief Financial Officer of Noble, which he was elected to 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 Chief Financial Officer of Shell Oil Products U.S. responsible for U.S. 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 on the board of directors of Apergy Corporation as a director and audit committee chairman. We believe Mr. Fisher’s energy industry and financial experience will provide the board of directors of our General Partner with valuable experience in our financial and accounting matters.

Thomas H. Walker was appointed to the board of directors of our General Partner in July 2018. Mr. Walker serves as Senior Vice President of Noble Energy, which he was appointed to in February 2018, and is currently responsible for Noble Energy’s U.S. Onshore operations. Mr. Walker previously served as Vice President of West Africa and the U.S. Gulf of Mexico from 2014 and Director of Strategic Planning, Environmental Analysis and Reserves, managed Noble Energy’s operated West Africa assets, non-operated international assets and frontier business ventures and was a member of Noble Energy’s business development team from 2007. Prior to joining Noble Energy in 2007, Mr. Walker held various positions at Amoco and BP America. We believe Mr. Walker’s extensive knowledge of the oil and gas industry and multi-basin operating management experience will provide the board of directors of our general partner with valuable experience.

Brent J. Smolik was appointed to the board of directors of our General Partner in November 2018. Mr. Smolik serves as President and Chief Operating Officer for Noble, which he was appointed to in November 2018. Before joining Noble in November 2018, Mr. Smolik served as President, Chief Executive Officer and Chairman of The Board of EP Energy

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Corporation and EP Energy LLC from 2012 through 2017.  He was previously Executive Vice President and a member of the Executive Committee of El Paso Corporation and President of the El Paso Exploration and Production Company. From 2004 - 2006, Mr. Smolik served as President of ConocoPhillips Canada and Burlington Resources Canada. From 1990-2004 he worked in numerous engineering and asset management capacities for Burlington Resources Inc., including the Chief Engineering role from 2000-2004.  He began his career with ARCO Oil and Gas in 1984. Mr. Smolik previously served on the boards of directors of Cameron International Corporation, America’s Natural Gas Alliance, and the Independent Petroleum Association of America and the American Exploration and Production Council. We believe Mr. Smolik’s technical, operating and leadership experience in the energy industry will provide the board of directors of our General Partner with valuable experience.

Hallie A. Vanderhider was appointed to the board of directors of our General Partner in September 2016 and serves as chair of the audit committee and a member of the conflicts committee. Ms. Vanderhider currently serves as Managing Director of SFC Energy Management, L.P. Ms. Vanderhider previously served as the Managing Partner of Catalyst Partners, LLC, from May 2013 to June 2018. Previously, she served as a member of the board of directors and as the President and Chief Operating Officer at Black Stone Minerals Company, L.P. (Black Stone), from October 2007 through May 2013. She joined Black Stone in 2003 and served as its Executive Vice President and Chief Financial Officer until being appointed as the President and Chief Operating Officer in 2007. Ms. Vanderhider served as Chief Financial Officer of EnCap Investments L.P. and served in a variety of positions at Damson Oil Corp., including as Chief Accounting Officer. In addition, she served on the following boards of directors: Mississippi Resources LLC, from August 2014 to February 2016; PetroLogistics GP LLC, from April 2013 to July 2014; Bright Horizons LLC from October 2013 to January 2016; Armor Energy LLC, Frostwood Energy, LLC, and Greystone Petroleum, LLC from May 2016 to present; and Grey Rock Energy Management LLC from August 2013 to present. We believe that Ms. Vanderhider’s previous experience with master limited partnerships and the natural resource industry, as well as her knowledge of financial statements, will provide her the necessary skills to be a member of the board of directors of our General Partner.

Martin Salinas, Jr. was appointed to the board of directors of our General Partner in October 2016 and is a member of the audit committee and a member of the conflicts committee. Mr. Salinas served as the Chief Executive Officer of Phase 4 Energy Partners, Inc., from October 2015 to December 2018. Previously, he served as Chief Financial Officer of Energy Transfer Partners, L.P. from June 2008 through April of 2015. He joined Energy Transfer Partners, L.P. in 2004 and served as Controller and Vice-President of Finance until being appointed as Chief Financial Officer in 2008. In addition to serving as Chief Financial Officer for Energy Transfer Partners, Mr. Salinas also served as Sunoco Logistics, L.P.’s Chief Financial Officer and a member of its Board of Directors from October 2012 through April 2015 and as a member of the Board of Directors for Sunoco Partners, L.P. from March 2014 until April 2015. Prior to joining Energy Transfer Partners, L.P., Mr. Salinas worked at KPMG, LLP from September 1994 through August 2004 serving audit clients primarily in the Oil and Gas industry. Mr. Salinas was appointed to the board of directors for Green Plains Partners LP in July 2018. We believe that Mr. Salinas’s prior experience as an auditor and chief financial officer will provide the board of directors of our General Partner with valuable experience with respect to our accounting and financial matters.

Andrew E. Viens was appointed to the board of directors of our General Partner in June 2017. Mr. Viens evaluated potential business opportunities between April 2015 and June 2017. Mr. Viens was President, Global Marketing, for Phillips 66 until April 15, 2015 when he retired. He has 35 years of experience in various roles throughout the oil and gas and downstream industries. He was also a director on the DCP Midstream board from July 2012 until his retirement in April 2015. Before joining Phillips 66 in May 2012, as President, Global Marketing, Mr. Viens had held the same role with ConocoPhillips since March 2010. He had served as President, U.S. Marketing since May 2009. Previously, he held the position of General Manager, Commercial Marine from March 2007 to April 2009. He was appointed Manager, Heavy Products Trading in October 2003 after working as General Manager, Business Optimization. Prior to his career with ConocoPhillips, Mr. Viens worked for Tosco, and from April 1999 through the Phillips Petroleum acquisition of Tosco and through the Conoco and Phillips merger, he served as Manager of Wholesale Marketing and Diversified Business. His Tosco career had started in 1997 when he moved to Tempe as Manager of Product Supply and Trading. We believe that Mr. Vien’s prior experience in the energy industry will provide the board of directors of our General Partner with valuable experience.

John F. Bookout, IV was appointed Chief Financial Officer in October 2015. Mr. Bookout joined Noble in July 2014 and has recently been responsible for financial management, planning, business development, and mergers and acquisitions related to Noble’s U.S. onshore midstream activities, including the structuring of CONE Midstream Partners, L.P. and the structuring of the IPO of the Partnership. Mr. Bookout also served as an advisor to Noble in the Corporate Finance and Treasury group beginning in July 2014. From September 2009 until joining Noble, Mr. Bookout was an Associate at Global Infrastructure Partners.

Thomas W. Christensen was appointed Chief Accounting Officer in August 2016. He previously served as Corporate Finance Manager in Noble’s Treasury group since joining Noble following its acquisition of Rosetta Resources in July 2015. Mr. Christensen joined Rosetta Resources in September 2009 and served in positions of increasing responsibility, including serving

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as its Financial Reporting Manager from March 2011 to September 2013 and as its Assistant Controller overseeing SEC reporting, corporate accounting, income taxes and technical accounting matters from September 2013 to July 2015. Prior to joining Rosetta, Mr. Christensen worked as an auditor in PricewaterhouseCoopers’ energy practice. Mr. Christensen is a certified public accountant.

John C. Nicholson was appointed Chief Operating Officer in October 2015. Mr. Nicholson joined Noble in June 2007 and has held various engineering, operations and financial positions of increasing responsibility, both domestically and internationally. Mr. Nicholson previously served in Investor Relations for Noble from July 2014 until his appointment to Chief Operating Officer and served as a Project Manager for a deepwater development offshore West Africa from January 2012 to July 2014.

Harry R. Beaudry was appointed General Counsel and Secretary in October 2018. Mr. Beaudry has also served as Associate General Counsel of Noble Energy since joining in March 2017, with responsibility for the corporate services and midstream legal functions. Prior to joining Noble, Mr. Beaudry was a partner practicing corporate and securities law at the law firm of Mayer Brown LLP, which he joined in January 2013. From October 2000 to January 2013, Mr. Beaudry practiced corporate and securities law at the law firm of Thompson & Knight LLP.

Section 16(a) Beneficial Ownership Reporting Compliance 

Section 16(a) of the Exchange Act requires directors, executive officers and persons who beneficially own more than ten percent of a registered class of our equity securities (collectively, “Insiders”) to file with the SEC initial reports of ownership and reports of changes in ownership of such equity securities. Insiders are also required to furnish us with copies of all Section 16(a) forms that they file. Such reports are accessible on or through our website at www.nblmidstream.com under the “SEC Filings” tab.

Based solely upon a review of the copies of Forms 3 and 4 furnished to us, or written representations from certain reporting persons that no Forms 5 were required, we believe that the Insiders complied with all filing requirements with respect to transactions in our equity securities during 2018, with the following exception: the Form 3 filing for Mr. Brent J. Smolik in connection with his appointment to the board of directors of Noble Midstream GP LLC on November 26, 2018 was late.

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Item 11.  Executive Compensation

Compensation Discussion and Analysis

Neither we nor our General Partner employ any of the individuals who serve as executive officers of our General Partner and are responsible for managing our business. We are managed by our General Partner, the executive officers of which are employees of Noble and perform responsibilities for Noble and its affiliates unrelated to our business. Because our General Partner’s executive officers are employed by Noble, compensation of our executive officers is set and paid by Noble under its compensation programs. While our General Partner has not entered into any employment agreements with any of its executive officers, we and our General Partner have entered into an omnibus agreement (the Omnibus Agreement) and an operational services and secondment agreement (the Operational Services Agreement), in each case, with Noble. Pursuant to the terms of the Operational Services Agreement, we reimburse Noble for the portion of our chief executive officer’s and chief operating officer’s compensation that is attributable to the management of the operational aspects of our business. Pursuant to the terms of the Omnibus Agreement, we pay an annual fixed administrative fee to Noble, which covers the services provided to us by all of our other executive officers. Except with respect to awards that may be granted under the Noble Midstream Partners LP 2016 Long-Term Incentive Plan (the LTIP), our executive officers do not receive any separate compensation for their services to our business or as executive officers of our General Partner.

For 2018, our Named Executive Officers (the NEOs) were:

• Terry R. Gerhart, Chief Executive Officer;

• John F. Bookout, IV, Chief Financial Officer;

• John C. Nicholson, Chief Operating Officer;

• Thomas W. Christensen, Chief Accounting Officer; and

• Harry R. Beaudry, General Counsel and Secretary.

Mr. Gerhart, who is also an executive officer of Noble, devotes a portion of his time to his role at Noble and spends time, as needed, managing our business and affairs. In fiscal year 2018, Mr. Gerhart devoted approximately 60% of his time to managing our business and affairs. Mr. Beaudry was appointed an executive officer of our General Partner in October 2018. In fiscal year 2018, Mr. Beaudry devoted approximately 50% of his time to managing our business and affairs. Messrs. Bookout, Nicholson, and Christensen are employees of Noble and devote substantially all of their working time to us and our General Partner.

Elements of Compensation

Noble provides compensation to our executives in the form of base salaries, annual cash incentive awards, long-term equity incentive awards and participation in various employee benefits plans and arrangements. The chart below shows the target compensation mix for Messrs. Gerhart, Bookout, Nicholson and Christensen based on their base salaries at the end of 2018. The chart below excludes the supplemental restricted unit awards and supplemental cliff vesting restricted shares of Noble stock granted in February 2018 to Messrs. Bookout and Nicholson. Because Mr. Beaudry was not appointed an executive officer until October 2018, he has been excluded from the chart below.

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The following sets forth a more detailed explanation of the elements of Noble’s compensation programs as they relate to Messrs. Gerhart, Bookout, Nicholson, Christensen and Beaudry.

Base Salary

Base salary is designed to provide a competitive fixed rate of pay recognizing employees’ different levels of responsibility and performance. In setting an executive’s base salary, Noble considers several factors, including external market data, the internal worth and value assigned to the executive’s role and responsibilities at Noble, and the executive’s skills, experience, expertise and performance.

Name	Base Salary as of 12/31/2017 ($)	Base Salary as of 12/31/2018 ($)	Percentage Increase
Terry R. Gerhart	—	237,000	N/A
John F. Bookout, IV	230,000	230,000	—	%
John C. Nicholson	230,000	230,000	—	%
Thomas W. Christensen	178,000	200,000	12	%
Harry R. Beaudry	—	137,500	N/A

Short-Term Incentive Plan

Noble’s short-term incentive plan (the STIP) provides participants with an opportunity to earn performance-based annual cash bonus awards. Target annual bonus levels are established at or before the beginning of each year and are based on a percentage of the executive’s base salary. The table below provides annual bonus targets and maximum potential payouts for 2018 for each of Messrs. Gerhart, Bookout, Nicholson, Christensen and Beaudry.

Name	Target (as a % of Base Salary)
Terry R. Gerhart	65	%
John F. Bookout, IV	35	%
John C. Nicholson	35	%
Thomas W. Christensen	30	%
Harry R. Beaudry	35	%

The STIP is weighted 60% on quantitative measures and 40% on qualitative measures. The performance goals are designed to motivate performance and compensate employees for annual contributions. Based on the results of Noble’s performance versus its qualitative and quantitative targets, Noble arrived at an overall company performance factor of 85% of target for the 2018 STIP.

2018 STIP Payments

The cash payout under the STIP occurred in February 2018, and the following table shows the final STIP payouts to our Named Executive Officers:

Name	2018 STIP Payout ($)
Terry R. Gerhart	131,421
John F. Bookout, IV	79,407
John C. Nicholson	79,407
Thomas W. Christensen	53,485
Harry R. Beaudry	39,216

Long-Term Equity-Based Compensation Awards

Our Named Executive Officers are eligible to participate in the LTIP and Noble’s equity compensation programs.

Time-Based Restricted Units

The board grants these time-based restricted units to provide a retention incentive to the Named Executive Officers and align the interests of our Named Executive Officers with our unitholders.

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In February 2018, Messrs. Gerhart, Bookout, Nicholson and Christensen received a grant of time-based restricted units under the LTIP. As Mr. Beaudry became a Named Executive Officer during October 2018, he did not receive a grant of time-based restricted units under the LTIP in February 2018. These restricted units will vest, subject to the conditions set forth in the applicable award agreements, as follows:

Vesting Date	Portion of the Restricted Units that Become Vested
February 1, 2019	20	%
February 1, 2020	30	%
February 1, 2021	50	%

Also during 2018, Messrs. Bookout, Nicholson and Beaudry received a grant of time-based restricted units under the LTIP that vest on the third anniversary of the grant date. These restricted units will vest as follows:

Name	Vesting Date
John F. Bookout, IV	February 1, 2021
John C. Nicholson	February 1, 2021
Harry R. Beaudry	October 1, 2021

Noble Equity Compensation Awards

Under Noble’s 1992 Stock Option and Restricted Stock Plan (the 1992 Plan), as amended from time to time, and Noble’s 2017 Stock Option and Restricted Stock Plan (the 2017 Plan) our Named Executive Officers may receive grants of stock options, restricted stock and performance awards. Equity‑based awards under the 2017 Plan received by our Named Executive Officers in 2018 included time-based restricted shares and stock options. The time-based restricted shares vest 20%, 30%, and 50% on the first, second, and third anniversaries of the date of grant, respectively. Certain time-based restricted shares vest on the third anniversary of the grant date. The stock options become exercisable as to one-third of the shares subject to the award on each of the first, second, and third anniversaries of the date of grant.

Retirement and Additional Benefits

Our Named Executive Officers are also eligible to participate in the employee benefit plans and programs that Noble offers to its employees, subject to the terms and eligibility requirements of those plans. During 2018, our Named Executive Officers participated in Noble’s 401(k) plan. Noble provides dollar-for-dollar matching contributions up to 6% of a participant’s eligible compensation. All of our Named Executive Officers are fully vested in their Company matching contributions. In addition, Noble makes the following age-weighted contributions to the 401(k) plan for each participant, including the Named Executive Officers:

Age of Participant	Contribution Percentage (Below the Social Security Wage Base)	Contribution Percentage (Above the Social Security Wage Base)
Under 35	4%	8%
At Least 35 but Under 48	7%	10%
48 and Over	9%	12%

Post-Employment Compensation Programs

Noble maintains the 2016 Severance Benefit Plan (the Severance Plan), which provides severance benefits to certain eligible employees, including our Named Executive Officers, upon their termination of employment in connection with a designated reduction in force. Noble also maintains the 2016 Change of Control Severance Plan (the COC Plan), in which each of our Named Executive Officers participate. The COC Plan provides for certain severance benefits upon an involuntary termination of employment within two years (and in certain circumstances, only one year) following a change of control of Noble.

Pursuant to the terms of the restricted unit awards held by our Named Executive Officers, upon certain terminations of employment, the restricted units will accelerate and become fully vested. Additionally, the stock options granted to our Named Executive Officers by Noble become fully exercisable upon certain terminations of employment, and the restricted shares will accelerate and become fully vested upon certain terminations of employment.

Please see “Potential Payments Upon Termination or a Change of Control” below for more detail regarding these post-employment compensation arrangements.

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Other Compensation Items

Tax and Accounting Implications

We account for equity compensation expenses under the rules of FASB ASC Topic 718, which require us to estimate and record an expense for each award of equity compensation over the vesting period of the award. Accounting rules also require us to record cash compensation, such as the compensation reimbursed pursuant to our Operational Services Agreement as an expense at the time the obligation is accrued. The board has taken into account the tax implications to us in its decision to grant equity incentive awards in the form of restricted units, as opposed to options or unit appreciation rights.

Unit Ownership Guidelines

We maintain unit ownership guidelines for our officers and non-employee directors. We believe that these guidelines reinforce the alignment of the long‑term interests of our Named Executive Officers and unitholders and help discourage excessive risk-taking. Each Named Executive Officer is expected to hold Common Units with a value equal to at least their base salary. The Named Executive Officers have five years from our IPO to achieve compliance. Named Executive Officers who are not in compliance with the unit ownership guidelines will be required to retain 50% of any net units they subsequently acquire upon vesting until the required ownership multiple is achieved. As of February 15, 2019, all Named Executive Officers were in compliance with the guidelines or were within the permitted time frame to come into compliance with the guidelines.

Risk Assessment

We are managed and operated by the officers of our General Partner, and employees of Noble provide services to us through the Operational Services Agreement and the Omnibus Agreement. Other than with respect to equity incentive awards approved by the board pursuant to the LTIP, we do not have any compensation policies or practices that need to be assessed or evaluated for the effect on our operations. The board believes that the grant of equity incentive awards pursuant to the LTIP does not encourage excessive and unnecessary risk taking, and the level of risk that it does encourage is not reasonably likely to have a material adverse effect on us. For an analysis of any risks arising from Noble’s compensation policies and practices, please read Noble’s 2019 Proxy Statement (which is not, and shall not be deemed to be, incorporated by reference herein), which we expect will be filed with the SEC not later than 120 days subsequent to December 31, 2018.

Actions Taken Following Fiscal-Year End

In February 2019, the board approved awards of restricted units to each of our Named Executive Officers. The restricted units granted to each of our Named Executive Officers vest 20%, 30%, and 50% on the first, second, and third anniversaries of the date of grant, respectively. Also in February 2019, the board approved awards of restricted units to Messrs. Bookout, Nicholson and Christensen. The restricted units granted to Messrs. Bookout, Nicholson and Christensen vest on the third anniversary of the grant date

Compensation Committee Interlocks and Insider Participation 

As a limited partnership, the board of directors of our general partner is not required by the rules of the NYSE to have a compensation committee. None of the executive officers of our general partner serve on the board of directors or compensation committee of a company that has an executive officer that serves on the board of directors of our general partner. No member of the board of directors of our general partner is an executive officer of a company in which one of the executive officers of our general partner serves as a member of the board of directors or compensation committee of that company.  

Compensation Committee Report

The following report of the board on executive compensation shall not be deemed to be “soliciting material” or to be “filed” with the SEC nor shall this information be incorporated by reference into any future filing made with the SEC, whether made before or after the date hereof and irrespective of any general incorporation language in such filing.

We do not maintain a separate compensation committee. As a result, the board has reviewed and discussed with management the Compensation Discussion and Analysis set forth herein and, based on such review and discussions, determined that it be included in this Annual Report.

Submitted by:	Terry R. Gerhart
	Kenneth M. Fisher
	Thomas H. Walker
	Brent J. Smolik
	Hallie A. Vanderhider
	Martin Salinas, Jr.
	Andrew E. Viens

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Summary Compensation Table

The following summarizes the total compensation paid to our Named Executive Officers for their services to us during the fiscal years ending December 31, 2018 and December 31, 2017 and the portion of the fiscal year ending December 31, 2016 following our IPO. Except as specifically noted, the amounts included in that able below reflect the portion of the expense allocated to us by Noble based on the percentage of each Named Executive Officer’s overall working time was devoted to our business for the applicable fiscal year.

Name and Principal Position	Year	Salary ($)	Bonus ($)	Stock Awards ($) (4)	Option Awards ($) (5)	Non-Equity Incentive Compensation ($)	All Other Compensation ($) (6)	Total ($)
Terry R. Gerhart (Chief Executive Officer and Director)(1)	2018	234,536	—	794,961	45,000	131,421	47,498	1,253,416
	2017	—	—	139,984	—	—	5,585	145,569
	2016	—	—	—	—	—	—	—
John F. Bookout, IV (Chief Financial Officer)(2)	2018	230,000	—	625,834	—	79,407	52,915	988,156
	2017	184,423	10,000	241,290	20,447	129,423	29,777	615,360
	2016	44,055	50,000	9,092	3,035	14,952	6,105	127,239
John C. Nicholson (Chief Operating Officer)(2)	2018	230,000	—	627,963	—	79,407	53,916	991,286
	2017	189,423	—	277,613	29,212	112,864	31,836	640,948
	2016	48,868	40,000	18,792	6,265	19,478	6,883	140,286
Thomas W. Christensen (Chief Accounting Officer)(2)	2018	194,070	—	85,374	—	53,485	34,985	367,914
	2017	177,424	—	150,259	20,434	65,673	30,019	443,809
	2016	48,819	—	15,165	15,165	20,728	6,432	106,309
Harry R. Beaudry (General Counsel and Secretary)(3)	2018	132,019	—	231,236		39,216	27,960	430,431

⁽¹⁾  For 2018, Mr. Gerhart devoted approximately 60% of his overall working time to our business and the amounts are prorated to reflect this. For 2017, Mr. Gerhart devoted approximately 15% of his overall working time to our business, and during 2017, the compensation he received from Noble in relation to the services he provides for us did not comprise a material amount of his total compensation.

⁽²⁾  Messrs. Bookout, Nicholson and Christensen devote substantially all of their overall working time to our business. The amounts set forth above reflect the portion of our Named Executive Officers’ compensation that is attributable to the management of the operational aspects of our business. For 2016, the amounts reported for each of Messrs. Bookout, Nicholson, and Christensen were prorated from the time of our formation in connection with our IPO on September 20, 2016.

⁽³⁾  Mr. Beaudry devoted approximately 50% of his overall working time to our business and the amounts are prorated to reflect this.

⁽⁴⁾  Reflects the aggregate grant date fair value of restricted stock and performance awards granted under the 2017 Plan and of restricted units awarded under our LTIP, each of which were computed in accordance with FASB ASC Topic 718. For more information regarding the restricted units, please see Item 8. Financial Statements and Supplementary Data – Note 11. Unit-Based Compensation to our financial statements for the fiscal year ended December 31, 2018. For more information regarding the restricted stock and performance awards, please see Noble’s Form 10-K for the year ended December 31, 2018 (which is not, and shall not be deemed to be, incorporated by reference herein).

⁽⁵⁾  Reflects the aggregate grant date fair value of non-qualified stock options granted under Noble’s 2017 Plan computed in accordance with FASB ASC Topic 718. For more information regarding the stock options, please see Noble’s Form 10-K for the year ended December 31, 2018 (which is not, and shall not be deemed to be, incorporated by reference herein).

⁽⁶⁾  All other compensation includes:

Name	401(k) Matching Contributions ($)	401(k) Retirement Savings Contributions ($)	Accrued Dividends ($)	Total All Other Compensation ($)
Terry R. Gerhart	9,900	12,000	25,598	47,498
John F. Bookout, IV	13,800	13,264	25,851	52,915
John C. Nicholson	13,800	13,264	26,852	53,916
Thomas W. Christensen	11,644	15,555	7,786	34,985
Harry R. Beaudry	7,921	10,329	9,710	27,960

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Grants of Plan-Based Awards

The table below sets forth information regarding grants of plan-based awards made to our Named Executive Officers during 2018. Except for the restricted units granted under our LTIP, the number of securities and dollar amounts set forth on the table below reflect an allocation based on the percentage of each Named Executive Officer’s overall working time that was devoted to our business during 2018.

Name	Approval Date (1)	Grant Date (1)	Estimated Future Payouts Under Non-Equity Incentive Plan Awards (2)			Estimated Future Payouts Under Equity Incentive Plan Awards (3)			All Other Stock Awards: Number of Shares or Units (#)		All Other Option Awards: Number of Securities Underlying Options (#)		Exercise or Base Price of Option Awards ($/Sh)	Grant Date Fair Value of Stock and Option Awards ($)(11)
			Threshold ($)	Target ($)	Max ($)	Threshold (#)	Target (#)	Max (#)
Terry R. Gerhart	1/29/2018	2/1/2018	—	256,750	—	—	—	—	—		—		—	—
	1/29/2018	2/1/2018	—	—	—	2,428	4,856	9,712	—		—		—	189,967
	1/29/2018	2/1/2018		—	—	—	—	—	8,809	(4)	—		—	499,999
	1/29/2018	2/1/2018		—	—	—	—	—	3,399	(5)	—		—	104,995
	1/29/2018	2/1/2018		—	—	—	—	—	—		4,298	(10)	30.89	45,000
John F. Bookout, IV	1/29/2018	2/1/2018	—	80,500	—	—	—	—	—		—		—	—
	1/29/2018	2/1/2018	—	—	—	—	—	—	1,461	(4)	—		—	82,926
	1/29/2018	2/1/2018	—	—	—	—	—	—	4,052	(6)	—		—	229,992
	1/29/2018	2/1/2018	—	—	—	—	—	—	2,685	(7)	—		—	82,940
	1/29/2018	2/1/2018	—	—	—	—	—	—	7,445	(8)	—		—	229,976
John C. Nicholson	1/29/2018	2/1/2018	—	80,500	—	—	—	—	—		—		—	—
	1/29/2018	2/1/2018	—	—	—	—	—	—	1,480	(4)	—		—	84,005
	1/29/2018	2/1/2018	—	—	—	—	—	—	4,052	(6)	—		—	229,992
	1/29/2018	2/1/2018	—	—	—	—	—	—	2,719	(7)	—		—	83,990
	1/29/2018	2/1/2018	—	—	—	—	—	—	7,445	(8)	—		—	229,976
Thomas W. Christensen	1/29/2018	2/1/2018	—	60,000	—	—	—	—	—		—		—	—
	1/29/2018	2/1/2018	—	—	—	—	—	—	752	(4)	—		—	42,684
	1/29/2018	2/1/2018	—	—	—	—	—	—	1,382	(7)	—		—	42,690
Harry R. Beaudry	1/29/2018	2/1/2018	—	48,125	—	—	—	—	—		—		—	—
	1/29/2018	2/1/2018	—	—	—	—	—	—	2,630	(7)	—		—	81,241
	1/29/2018	2/1/2018	—	—	—	—	—	—	3,847	(9)	—		—	149,995

⁽¹⁾  All grants were approved by the board or by Noble (or its board of directors or compensation committee), as applicable, on the approval date set forth above, but such grants became effective and were valued on the grant date set forth above.

⁽²⁾  The amounts in this column represent the target and maximum payouts under Noble’s 2018 STIP. There is no threshold amount under the STIP. Actual payouts under the STIP were determined based on Noble’s achievement against specified performance measures. For more information, please see the section entitled “Short-Term Incentive Plan” in our “Compensation Discussion and Analysis” above.

⁽³⁾  Represents the shares of performance awards granted under Noble's 2017 Plan in 2018. The shares will vest February 1, 2021 if specified performance goals are satisfied.

⁽⁴⁾  These grants of restricted units under our LTIP became vested as to 20% on February 1, 2019 and will become vested as to 30% on February 1, 2020 and 50% on February 1, 2021, subject to the applicable Named Executive Officer’s continued employment through each vesting date.

⁽⁵⁾  These grants of restricted shares of Noble stock under the 2017 Plan became vested as to 33 1/3% on February 1, 2019 and will become vested as to 33 1/3% on February 1, 2020 and 33 1/3% on February 1, 2021, subject to the applicable Named Executive Officer’s continued employment through each vesting date.

⁽⁶⁾  These grants of restricted units under our LTIP will become vested on February 1, 2021, subject to the applicable Named Executive Officer’s continued employment through such vesting date.

⁽⁷⁾  These grants of restricted shares of Noble stock under the 2017 Plan became vested as to 20% on February 1, 2019 and will become vested as to 30% on February 1, 2020 and 50% on February 1, 2021, subject to the applicable Named Executive Officer’s continued employment through each vesting date.

⁽⁸⁾  These grants of restricted shares of Noble stock under the 2017 Plan will become vested on February 1, 2021, subject to the applicable Named Executive Officer’s continued employment through such vesting date.

⁽⁹⁾  These grants of restricted units under our LTIP will become vested on October 1, 2021, subject to the applicable Named Executive Officer’s continued employment through such vesting date.

⁽¹⁰⁾  These stock options granted under the 2017 Plan became exercisable as to 1/3 of the shares of Noble stock underlying each option on February 1, 2019 and will become exercisable as to 1/3 of the shares on each of February 1, 2020, and February 1, 2021, subject to the applicable Named Executive Officer’s continued employment through each vesting date.

⁽¹¹⁾  Reflects the aggregate grant date fair value of restricted stock, performance awards and non-qualified stock options granted under Noble’s 2017 Plan and restricted units granted under our LTIP, in each case computed in accordance with FASB ASC Topic 718. For more information regarding the restricted units, please see Item 8. Financial Statements and Supplementary Data – Note 11. Unit-Based Compensation to our financial statements for the fiscal year ended December 31, 2018. For more information regarding the restricted stock, performance awards and stock options, please see Noble’s Form 10-K for the year ended December 31, 2018 (which is not, and shall not be deemed to be, incorporated by reference herein).

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Outstanding Equity Awards at Fiscal Year-End

The table below sets forth information regarding stock options, restricted stock, performance awards and restricted units held by our Named Executive Officers as of December 31, 2018. Except for the restricted units granted under our LTIP, the number of securities set forth on the table below reflect an allocation based on the percentage of each Named Executive Officer’s overall working time that was devoted to our business during 2018.

	Option Awards (1)					Stock Awards
Name	Number of Securities Underlying Unexercised Options (#) Exercisable	Number of Securities Underlying Unexercised Options (#) Unexercisable		Option Exercise Price ($)	Option Expiration Date	Number of Shares or Units of Stock Held That Have Not Vested (#)		Market Value of Shares or Units of Stock Held That Have Not Vested ($)(18)	Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested (#)		Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested ($)(18)
Terry R. Gerhart	11,400	—		36.67	12/28/2019	850	(6)	15,946	4,202	(19)	78,830
	9,396	—		37.55	2/1/2020	3,399	(7)	63,765	3,548	(20)	66,560
	7,548	—		45.20	2/1/2021	2,544	(8)	73,369	4,856	(21)	91,099
	9,724	—		50.91	2/1/2022	8,809	(9)	254,052	—		—
	1,508	—		50.91	2/1/2022	—		—	—		—
	8,161	—		54.60	2/1/2023	—		—	—		—
	697	—		56.52	4/29/2023	—		—	—		—
	6,498	—		62.33	1/31/2024	—		—	—		—
	8,152	—		47.74	1/30/2025	—		—	—		—
	8,779	4,390	(2)	31.65	2/1/2026	—		—	—		—
	3,519	7,039	(3)	39.46	2/1/2027	—		—	—		—
	—	4,298	(4)	30.89	2/1/2028	—		—	—		—
John F. Bookout, IV	936	—		47.74	1/30/2025	509	(10)	9,549	—		—
	710	355	(2)	31.65	2/1/2026	415	(11)	7,785	—		—
	514	1,028	(3)	39.46	2/1/2027	7,445	(12)	139,668	—		—
	—	—		—	—	2,685	(13)	50,371	—		—
	—	—		—	—	744	(8)	21,457	—		—
	—	—		—	—	3,924	(14)	113,168	—		—
	—	—		—	—	4,052	(15)	116,860	—		—
	—	—		—	—	1,461	(9)	42,135	—		—
John C. Nicholson	531	—		50.91	2/1/2022	1,052	(10)	19,736	—		—
	886	—		54.60	2/1/2023	592	(11)	11,106	—		—
	1,205	—		62.33	1/31/2024	7,445	(12)	139,668	—		—
	1,619	—		47.74	1/30/2025	2,719	(13)	51,008	—		—
	—	733	(2)	31.65	2/1/2026	1,062	(8)	30,628	—		—
	734	1,469	(3)	39.46	2/1/2027	4,143	(14)	119,484	—		—
	—	—		—	—	4,052	(15)	116,860	—		—
	—	—		—	—	1,480	(9)	42,683	—		—
Thomas W. Christensen	1,183	592	(2)	31.65	2/1/2026	849	(10)	15,927	—		—
	513	1,028	(3)	39.46	2/1/2027	415	(11)	7,785	—		—
	—	—		—	—	1,382	(13)	25,926	—		—
	—	—		—	—	743	(8)	21,428	—		—
	—	—		—	—	1,940	(14)	55,950	—		—
	—	—		—	—	752	(9)	21,688	—		—
Harry R. Beaudry	504	1,008	(5)	32.85	03/27/2027	1,219	(16)	22,868	—		—
	—	—		—	—	2,630	(13)	49,339	—		—
	—	—		—	—	3,847	(17)	110,947	—		—

⁽¹⁾  The option awards in these columns are options to purchase shares of Noble stock granted under the 1992 Plan or 2017 Plan.

⁽²⁾  These options became exercisable on February 1, 2019.

⁽³⁾  One-half of these options became exercisable on February 1, 2019, and the remaining one-half will become exercisable on February 1, 2020, subject to the applicable Named Executive Officer’s continued employment through such vesting date.

⁽⁴⁾  One-third of these options became exercisable on February 1, 2019, and the remaining options will become exercisable as to one-third of the shares subject to the options on each of February 1, 2020 and February 1, 2021, subject to the applicable Named Executive Officer’s continued employment through each vesting date.

⁽⁵⁾  One-half of these options will become exercisable on March 27, 2019, and the remaining one-half will become exercisable on March 27, 2020, subject to the applicable Named Executive Officer’s continued employment through such vesting date.

⁽⁶⁾  These restricted shares of Noble stock vested on February 1, 2019.

⁽⁷⁾  One-third of these restricted shares of Noble stock granted under the 2017 Plan vested on February 1, 2019. One-Third of these restricted shares of Noble stock will vest on February 1, 2020, and the remaining one-third will vest on February 1, 2021, subject to the applicable Named Executive Officer’s continued employment through each vesting date.

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⁽⁸⁾  37.5% of these restricted units granted under our LTIP vested on February 1, 2019 and the remainder will vest on February 1, 2020, subject to the applicable Named Executive Officer’s continued employment through each vesting date.

⁽⁹⁾  20% of these restricted units granted under our LTIP vested on February 1, 2019, 30% of these restricted units will vest on February 1, 2020, and the remainder will vest on February 1, 2021, subject to the applicable Named Executive Officer’s continued employment through each vesting date.

⁽¹⁰⁾  These phantom units representing shares of Noble stock vested and were settled in cash on February 1, 2019.

⁽¹¹⁾  37% of these restricted shares of Noble stock granted under the 1992 Plan vested on February 1, 2019 and the remainder of these restricted shares of Noble stock will vest on February 1, 2020, subject to the applicable Named Executive Officer’s continued employment through each vesting date.

⁽¹²⁾  These restricted shares of Noble stock granted under the 2017 Plan will vest on February 1, 2021, subject to the applicable Named Executive Officer’s continued employment through each vesting date.

⁽¹³⁾  20% of these restricted shares of Noble granted under the 2017 Plan vested on February 1, 2019, 30% of these restricted shares will vest on February 1, 2020, and the remainder will vest on February 1, 2021, subject to the applicable Named Executive Officer’s continued employment through each vesting date.

⁽¹⁴⁾  These restricted units granted under our LTIP will vest on May 4, 2020, subject to the applicable Named Executive Officer’s continued employment through such vesting date.

⁽¹⁵⁾  These restricted units granted under our LTIP will vest on February 1, 2021, subject to the applicable Named Executive Officer’s continued employment through such vesting date.

⁽¹⁶⁾  37% of these restricted shares of Noble stock granted under the 1992 Plan will vest on March 27, 2019 and the remainder of these restricted shares of Noble stock will vest on March 27, 2020, subject to the applicable Named Executive Officer’s continued employment through each vesting date.

⁽¹⁷⁾  These restricted units granted under our LTIP will vest on October 1, 2021, subject to the applicable Named Executive Officer’s continued employment through such vesting date.

⁽¹⁸⁾  Amounts reported in these columns are calculated based on $28.84, the closing price of our Common Units on December 31, 2018, or $18.76, the closing price of Noble stock on December 31,2018, as applicable.

⁽¹⁹⁾  Based on Noble’s formula for calculating total shareholder levels relative to a pre-determined industry peer group, none of the shares of performance-based Noble restricted stock granted under the 1992 Plan vested on February 1, 2019.

⁽²⁰⁾  These shares of performance-based Noble restricted stock granted under the 1992 Plan will vest on February 1, 2020, subject to achievement of total stockholder return levels relative to a pre-determined industry peer group.

⁽²¹⁾  These shares of performance-based Noble restricted stock granted under the 2017 Plan will vest on February 1, 2021, subject to achievement of total stockholder return levels relative to a pre-determined industry peer group.

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Option Exercises and Stock Vested

The table below sets forth information regarding the exercise of stock options and the vesting of restricted awards during fiscal year 2018. Except for restricted units under our LTIP that vested in 2018, the number of securities set forth on the table below reflect an allocation based on the percentage of each Named Executive Officer’s overall working time that was devoted to our business during 2018.

	Option Awards		Stock Awards			Unit Awards
Name	Number of Shares Acquired on Exercise (#)	Value Realized on Exercise ($)(8)	Number of Shares Acquired on Vesting (#)		Value Realized on Vesting ($)(5)	Number of Shares Acquired on Vesting (#) (6)	Value Realized on Vesting ($)(7)
Terry R. Gerhart	—	—	986	(1)	30,470	636	36,099
John F. Bookout, IV	—	—	892	(2)	26,747	185	10,501
John C. Nicholson	1,465	7,385	1,616	(2)	48,522	265	15,041
Thomas W. Christensen	—	—	1,247	(3)	38,235	185	10,501
Harry R. Beaudry	—	—	305	(4)	9,199	—	—

⁽¹⁾  These amounts represent restricted stock awards granted on February 1, 2016 and February 1, 2017 which vested on February 1, 2018.

⁽²⁾  This amount represents restricted stock awards granted on February 1, 2016, February 1, 2017 and October 19, 2015 which vested on February 1, 2018, February 1, 2018 and October 19, 2018, respectively.

⁽³⁾  This amount represents restricted stock awards granted on February 1, 2016, February 1, 2017 and March 2, 2015 which vested on February 1, 2018, February 1, 2018 and March 2, 2018, respectively.

⁽⁴⁾  This amount represents restricted stock awards granted on March 27, 2017 which vested on March 27, 2018.

⁽⁵⁾  The value realized on the vesting of the restricted stock awards was calculated as the number of shares that vested (including Noble shares withheld for tax withholding purposes) multiplied by the closing price of Noble common stock on the applicable vesting date. Dividends that accrued on shares of restricted stock that vested were paid in 2018 as follows: Mr. Gerhart - $563; Mr. Bookout - $914; Mr. Nicholson - $1,652; Mr. Christensen - $1,248 and Mr. Beaudry - $122.

⁽⁶⁾  These amounts represent restricted unit awards granted on February 1, 2017, which vested on February 1, 2018.

⁽⁷⁾  The value realized on the vesting of the restricted unit awards was calculated as the number of units that vested (including NBLX units withheld for tax withholding purposes) multiplied by the closing price of NBLX Common Unit on the applicable vesting date. Distributions that accrued on units of restricted units that vested were paid in 2018 as follows: Mr. Gerhart - $1,117; Mr. Bookout - $325; Mr. Nicholson - $465; and Mr. Christensen - $325.

⁽⁸⁾  The value realized on the exercise of the stock options was calculated as the number of options that were exercised (including Noble shares withheld for tax withholding purposes) multiplied by the difference between the closing price of Noble common stock on the exercise date and the exercise price of the stock option.

Pension Benefits and Nonqualified Deferred Compensation

Our Named Executive Officers do not participate in a defined benefit pension plan or a nonqualified deferred compensation plan providing for retirement benefits.

Potential Payments Upon Termination or a Change of Control

Noble 2016 Severance Benefit Plan

Pursuant to the terms of the Severance Plan, upon a termination of a Named Executive Officer’s employment by Noble without “cause” as a result of a “designated reduction in force,” such Named Executive Officer will receive the following benefits: (i) a lump sum cash amount equal to such Named Executive Officer’s weekly base pay multiplied by the greater of 12 or the lesser of 52 or two times the number of such Named Executive Officer’s years of service, (ii) a lump sum cash amount equal to a pro-rata portion of such Named Executive Officer’s target bonus, (iii) continued medical, dental and vision benefits for a period of six months at a cost such Named Executive Officer equal to the premium paid by similarly situated active employees, and (iv) coverage under the employee assistance program for 12 weeks.

As used in the Severance Plan:

• A “designated reduction in force” generally means (a) the elimination of such Named Executive Officer’s job or position, (b) the permanent closing, restructuring, downsizing or reorganization of a business unit, or (c) certain corporate transactions to the extent such events are expressly designated as a designed reduction in force.

• “Cause” generally means (a) misconduct or neglect, (b) engaging in conduct detrimental to Noble, (c) a failure to devote full-time, loyalty, best efforts, and ability to the performance of an individual’s job duties, (d) failure to perform job duties, and (e) conviction of a felony or other criminal offense.

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Noble 2016 Change of Control Severance Plan

Pursuant to the terms of the COC Plan, upon the termination of a Named Executive Officer’s employment (i) by Noble within two years after a “change of control” of Noble, (ii) a resignation by such Named Executive Officer within two years after a change of control of Noble as a result of a material reduction in such Named Executive Officer’s base pay or target bonus opportunity, (iii) a resignation by such Named Executive Officer within two years after a change of control of Noble as a result of a significant reduction in the employee benefits and perquisites provided to such Named Executive Officer, or (iv) a resignation such Named Executive Officer within one year after a change of control of Noble as a result of a relocation of such Named Executive Officer’s principal place of employment by more than 50 miles, such Named Executive Officer would receive the following benefits: (a) a lump sum severance payment equal to the greater of three weeks of base pay for every year of service or two weeks base pay for every $10,000 of base salary, (b) a lump sum severance payment equal to the greater of a pro-rata portion of such Named Executive Officer’s target bonus or a pro-rata average of the bonuses actually received by the Named Executive Officer for the three years immediately preceding the year in which the change of control occurs, and (c) continued medical, dental and vision benefits for a period of six months at a cost to the Named Executive Officer equal to the premium paid by similarly situated active employees.

As used in the COC Plan, “change of control” generally means (a) the incumbent board members cease to constitute at least 51% of the board of directors of Noble, (b) a reorganization, merger or consolidation after which the pre-transaction stockholders do not own voting securities representing at least 51% of the combined voting power of the reorganized, merged or consolidated company, (c) liquidation or dissolution of Noble or sale of all or substantially all of the stock or assets of Noble, or (d) any person becomes the beneficial owner of 25% or more of the outstanding Noble common stock or the voting securities of Noble.

STIP

Pursuant to the terms of the STIP, upon a termination of employment prior to the date the STIP is paid, all rights to such payment are forfeited; however, upon a termination of employment as a result of a Named Executive Officer’s death prior to the date the STIP is paid, a target amount of the STIP will be paid.

NBLX Restricted Units

Under each Named Executive Officer’s time-based restricted unit award agreements, if the Named Executive Officer’s employment is terminated (i) as a result of the Named Executive Officer’s death or “disability” or (ii) without “cause” following a “change of control” of us, all unvested restricted units held by the Named Executive Officer will become vested as of the date of such termination. If the Named Executive Officer’s employment is terminated for any other reason, all unvested restricted units held by the Named Executive Officer will be forfeited as of the date of such termination.

As used in the restricted unit award agreements and the LTIP:

• “Cause” generally means dishonesty, theft, embezzlement from us, willful violation of our rules pertaining to the conduct of employees, a willful felonious act, or the violation of any non-compete, non-solicitation or other confidentiality agreement with Noble, our General Partner or their affiliates.

• “Change of control” generally means (a) any person or group acquires 50% or more of the combined voting power of us or our General Partner, (b) liquidation of us, (c) sale by us or our General Partner of all of our or the General Partner’s assets, other than any sale to us, the General Partner, or an affiliate thereof, or (d) transaction resulting in a person other than our General Partner or an affiliate thereof being the sole general partner of us.

• “Disability” generally means a physical or mental condition of a participant that would entitled him or her to payment of disability income payments under our, our General Partner’s or one of our affiliate’s long-term disability insurance policies or plans. If no such plan exists, then “disability” has the meaning set forth in Section 22(e)(3) of the Internal Revenue Code of 1986, as amended.

Noble Restricted Stock and Stock Options

Under the terms of the 1992 Plan and the 2017 Plan, if a Named Executive Officer’s employment is terminated as a result of such Named Executive Officer’s death or “disability,” all restricted stock will immediately vest. Further, upon a termination of a Named Executive Officer’s employment by Noble without “cause” or by the Named Executive Officer for “good reason,” in each case within 24-months following a change of control of Noble, all restricted stock will immediately vest. If a Named Executive Officer’s employment for any other reason, all shares of restricted stock will be immediately forfeited.

Under the terms of the 1992 Plan and the 2017 Plan, if a Named Executive Officer’s employment is terminated for cause, all options, whether or not exercisable, will immediately terminate. If a Named Executive Officer’s employment is terminated a result of such Named Executive Officer’s “retirement,” each exercisable option will remain exercisable through the earlier of the fifth anniversary of such retirement or the expiration of the option, and any unexercisable options will terminate on the date of such Named Executive Officer’s retirement. If a Named Executive Officer’s employment is terminated as a result of such

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Named Executive Officer’s death or disability, all options, whether or not exercisable, will become exercisable and remain exercisable through the earlier of the fifth anniversary of such death or disability or the expiration of the option. Further, upon a termination of a Named Executive Officer’s employment by Noble without cause or by the Named Executive Officer for good reason, in each case within 24-months following a change of control of Noble, all options will immediately become exercisable. Upon the termination of a Named Executive Officer’s employment for any other reason, exercisable options will remain exercisable through the earlier of the first anniversary of such termination or the expiration of the option.

As used in the 1992 Plan and 2017 Plan:

• “Cause” generally means (a) conviction of a felony or misdemeanor involving moral turpitude, (b) conduct involving a material misuse of funds or other property of Noble, (c) engagement in business activities which are in conflict with the business interests of Noble, (d) gross negligence or willful misconduct, (e) conduct that violates Noble’s safety rules or standards, or (f) material violation of Noble’s code of conduct.

• “Change of control” generally has the same meaning provided to such term in the COC Plan.

• “Disability” generally means a physical or mental condition of a participant that would entitled him or her to payment of disability income payments under Noble’s long-term disability insurance policies or plans. If no such plan exists, then “disability” means a medically determinable physical or mental impairment that prevents the participant from performing his or her duties in a satisfactory manner and is expected either to result in death or to last for a continuous period of not less than 12 months.

• “Good reason” generally means a (a) material reduction in base compensation, (b) material change in the location of employment, (c) material reduction in authority, duties or responsibilities of the participant or the participant’s direct supervisor, or (d) material reduction in the budget over which the participant retains authority.

• “Retirement” generally means a termination of employment occurring after the participant attains at least 55 years of age and completes at least five years of credited service.

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The table below sets forth the value of benefits that would be received by each Named Executive Officer upon each applicable termination scenario, assuming such termination occurred on December 31, 2018.

Name	Type of Payment or Benefit	Death ($)	Disability ($)	Involuntary Termination ($) (7)	Termination without Cause following a Change of Control of NBLX ($)	Termination without Cause or Involuntary Termination following a Change of Control of Noble ($)
Terry R. Gerhart	Cash Severance	—	—	393,481	—	1,650,887
	STIP Payments (1)	256,750	—	—	—	256,750
	NBLX Restricted Units (2)	358,754	358,754	—	358,754	—
	Noble Restricted Stock (3)	547,581	547,581	—	—	320,774
	Noble Stock Options (4)	—	—	—	—	—
	Continued Medical Benefits (5)	—	—	8,865	—	44,324
	Life Insurance (6)	790,000	—	—	—	—
	Total	1,953,085	906,335	402,346	358,754	2,272,735
John F. Bookout, IV	Cash Severance	—	—	133,577	—	203,462
	STIP Payments (1)	80,500	—	—	—	80,500
	NBLX Restricted Units (2)	321,435	321,435	—	321,435	—
	Noble Restricted Stock (3)	212,699	212,699		—	212,699
	Noble Stock Options (4)	—	—	—	—	—
	Continued Medical Benefits (5)	—	—	4,173	—	4,173
	Life Insurance (6)	460,000	—	—	—	—
	Total	1,074,634	534,134	137,750	321,435	500,834
John C. Nicholson	Cash Severance	—	—	183,115	—	203,462
	STIP Payments (1)	80,500	—	—	—	80,500
	NBLX Restricted Units (2)	339,783	339,483	—	339,483	—
	Noble Restricted Stock (3)	227,673	227,673	—	—	227,673
	Noble Stock Options (4)	—	—	—	—	—
	Continued Medical Benefits (5)	—	—	12,840	—	12,840
	Life Insurance (6)	460,000	—	—	—	—
	Total	1,107,956	567,156	195,955	339,483	524,475
Thomas W. Christensen	Cash Severance	—	—	106,154	—	153,846
	STIP Payments (1)	60,000	—	—	—	66,569
	NBLX Restricted Units (2)	110,131	110,131	—	110,131	—
	Noble Restricted Stock (3)	51,620	51,620	—	—	51,620
	Noble Stock Options (4)	—	—	—	—	—
	Continued Medical Benefits (5)	—	—	11,185	—	11,185
	Life Insurance (6)	400,000	—	—	—	—
	Total	621,751	161,751	117,339	110,131	283,220
Harry R. Beaudry	Cash Severance	—	—	159,712	—	290,865
	STIP Payments (1)	96,250	—	—	—	96,250
	NBLX Restricted Units (2)	113,100	113,100	—	113,100	—
	Noble Restricted Stock (3)	148,437	148,437	—	—	148,437
	Noble Stock Options (4)	—	—	—	—	—
	Continued Medical Benefits (5)	—	—	11,183	—	11,183
	Life Insurance (6)	550,000	—	—	—	—
	Total	907,787	261,537	170,895	113,100	546,735

⁽¹⁾  Named Executive Officers would not be entitled to a STIP payment for 2018 in the event of their termination of employment on December 31, 2018, other than in the event of a change of control or death.

⁽²⁾  Amounts reported in this row are calculated based on $28.84, the closing price of our Common Units on December 31, 2018 and includes accrued distributions.

⁽³⁾  Amounts reported in this row are calculated based on $18.76, the closing price of Noble stock on December 31,,2018 and includes accrued dividends.

⁽⁴⁾  Amounts reported in this row are calculated based on the difference between the applicable stock options for which exercisability would be accelerated and $18.76, the closing price of Noble stock on December 31, 2018. Because the exercise price of all options held by our Named Executive Officers exceeded $18.76, no value is associated with the acceleration of exercisability of these options.

⁽⁵⁾  Amounts reported in this row reflect the estimated cost to Noble of providing continued medical, dental and vision benefits.

⁽⁶⁾  Amounts in this row represent benefits paid pursuant to group term life insurance coverage provided by Noble equal to two times base salary, capped at $1,000,000. Noble’s group term life insurance coverage does not discriminate in scope, terms or operation, in favor of our Named Executive Officers, and it is available generally to all salaried employees.

⁽⁷⁾  The Named Executive Officers are not a party to any agreement that provides for a severance payment absent termination of employment following a change of control.  However, in certain instances the Noble Severance Plan provides for a severance payment  based upon years of completed service and continuation of certain health and welfare benefits.  If the Named Executive Officers are entitled to a severance payment under the plan, they would receive two weeks of pay for every year of service, not to exceed 52 weeks or be less than 12 weeks, plus a prorated STIP payment based on their STIP target percentage.  They would also be able to continue certain health and welfare benefits for six months at the current active employee rates.

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Director Compensation

The officers of our General Partner or of Noble who also serve as directors of our General Partner do not receive additional compensation for their service as members of the board of directors of our General Partner. Directors of our General Partner who are not officers of our General Partner or of Noble (non-employee directors) receive cash and equity-based compensation for their services as directors of our General Partner. Our General Partner’s non-employee director compensation program consists of the following:

• an annual retainer of $60,000;

• an additional annual retainer of $20,000 for each of the chair of the audit committee and the chair of the conflicts committee, as applicable; and

• an annual equity-based award granted under the LTIP, having a value as of the grant date of approximately $120,000.

Non-employee directors 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.

The following table provides information regarding the compensation earned by our non-employee directors during the year ended December 31, 2018.

Name	Fees Earned or Paid in Cash ($)	Unit Awards ($) (1)	Total ($)
Hallie A. Vanderhider	80,000	120,000	200,000
Martin Salinas, Jr.	80,000	120,000	200,000
Andrew E. Viens	60,000	120,000	180,000

⁽¹⁾  Amounts reported in this column reflect the aggregate grant date fair value of the restricted units, computed in accordance with FASB ASC Topic 718. For more information, please see Item 8. Financial Statements and Supplementary Data – Note 11. Unit-Based Compensation to our financial statements for the fiscal year ended December 31, 2018.

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Item 12.  Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters

The following tables set forth, as of February 15, 2019, the beneficial ownership of Common and Subordinated units of the Partnership and held by:

• each unitholder known by us to beneficially hold more than 5% of our outstanding units;

• each director of our General Partner;

• each named executive officer of our General Partner; and

• all of the directors and named executive officers of our General Partner as a group.

In addition, our General Partner owns a non-economic General Partner interest in us and Noble owns all of our IDRs.

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 tables have sole voting and sole investment power with respect to all units beneficially owned by them, subject to community property laws where applicable.

Name of Beneficial Owner	Common Units Beneficially Owned	Percentage of Common Units Beneficially Owned		Subordinated Units Beneficially Owned	Percentage of Subordinated Units Beneficially Owned		Percentage of Total Common Units and Subordinated Units Beneficially Owned
Noble Energy, Inc. 1001 Noble Energy Way Houston, Texas 77070	2,090,014	8.7	%	15,902,584	100	%	45.2	%	(1)
Tortoise Capital Advisors, L.L.C. 11550 Ash Street, Suite 300 Leawood, Kansas 66211	2,597,272	10.9	%	—	—	%	6.5	%	(2)
Harvest Fund Advisors LLC 100 W. Lancaster Avenue, Suite 200 Wayne, Pennsylvania 19087	2,397,031	10.1	%	—	—	%	6.0	%	(3)
Salient Capital Advisors, LLC 4265 San Felipe, 8th Floor Houston, Texas 77027	1,478,040	6.2	%	—	—	%	3.7	%	(4)

⁽¹⁾  Based upon its Schedule 13D/A filed with the SEC on February 14, 2019, with respect to its beneficial ownership of our Common and Subordinated units, Noble Energy has sole voting and dispositive power with respect to 17,992,598 units.

⁽²⁾  Based upon its Schedule 13G/A filed with the SEC on February 12, 2019, with respect to its beneficial ownership of our Common Units, Tortoise Capital Advisors, L.L.C. has sole voting and dispositive power with respect to 98,052 Common Units, shared voting power with respect to 2,260,417 Common Units, shared dispositive power with respect to 2,499,220 Common Units and beneficially owns in the aggregate 2,597,272 Common Units.

⁽³⁾  Based upon its Schedule 13G/A filed with the SEC on February 14, 2019, with respect to its beneficial ownership of our Common Units, Harvest Fund Advisors LLC has sole voting and dispositive power with respect to 2,397,031 Common Units.

⁽⁴⁾  Based upon its Schedule 13G filed with the SEC on January 15, 2019, with respect to its beneficial ownership of our Common Units, Salient Capital Advisors, LLC has sole voting and dispositive power with respect to 1,478,040 Common Units.

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Directors/Named Executive Officers	Total Common Units Beneficially Owned (1)	Percent of Total Outstanding
Terry R. Gerhart	43,244	*
Kenneth M. Fisher	14,500	*
Thomas H. Walker	500	*
Brent J. Smolik	—	*
Hallie A. Vanderhider	12,524	*
Martin Salinas, Jr.	19,524	*
Andrew E. Viens	10,491	*
John F. Bookout, IV	25,479	*
John C. Nicholson	21,754	*
Thomas W. Christensen	9,073	*
Harry R. Beaudry	6,862	—
All Directors and Executive Officers as a Group (11 persons)	163,951	*

* Less than 1%.

⁽¹⁾  None of the Common Units reported in this column are pledged as security.

The following table sets forth, as of February 15, 2019, the number of shares of Noble common stock beneficially owned by each of the directors and named executive officers of our General Partner and all of the directors and named executive officers of our General Partner as a group. Amounts shown below include options that are currently exercisable or that may become exercisable within 60 days of February 15, 2019 and the shares underlying deferred stock units and the shares underlying restricted stock units that will be settled within 60 days of February 15, 2019. 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.

Directors/Named Executive Officers	Total Shares of Common Stock Beneficially Owned	Percent of Total Outstanding
Terry R. Gerhart	182,838	*
Kenneth M. Fisher	710,007	*
Thomas H. Walker	111,474	*
Brent J. Smolik	184,833	*
Hallie A. Vanderhider	—	—
Martin Salinas, Jr.	—	—
Andrew E. Viens	—	—
John F. Bookout, IV	25,984	*
John C. Nicholson	30,774	*
Thomas W. Christensen	10,885	*
Harry R. Beaudry	14,982	—
All Directors and Executive Officers as a Group (11 persons)	1,271,777	*

* Less than 1%.

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Item 13.  Certain Relationships and Related Transactions, and Director Independence

Noble owns 2,090,014 Common Units and 15,902,584 Subordinated Units representing an aggregate 45.4% limited partner interest in us. In addition, our General Partner owns a non-economic General Partner interest in us and Noble owns all of our IDRs.

Distributions and Payments to Our General Partner and Its Affiliates

The following summarizes the distributions and payments made, or 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/IPO Stage

The consideration received by our General Partner and its affiliates, including Noble, in connection with the IPO for the contribution of the controlling interests in our DevCos to us:

• a total of 1,527,584 Common Units, representing a 4.8% limited partner interest in the Partnership;

• a total of 15,902,584 Subordinated Units, representing an approximate 50.0% limited partner interest in the Partnership;

• IDRs in the Partnership;

• an initial cash distribution of $296.8 million from the Partnership; and

• a non-economic General Partnership interest in the Partnership, through our General Partner, Noble Midstream GP LLC, which is not entitled to receive cash distributions.

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 2,090,014 Common Units and 15,902,584 Subordinated Units. Assuming we have sufficient cash available for distribution to pay the full minimum quarterly distribution on all of our outstanding Common and Subordinated Units for four quarters, Noble would receive an annual distribution of approximately $27 million on their units.

• In addition, if distributions exceed the minimum quarterly distribution and target distribution levels, the IDRs held by Noble will entitle it to increasing percentages of the distributions, up to 50% of the distributions above the highest target distribution level.

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 agreement, we reimburse Noble for the secondment to our General Partner of certain employees who provide operational functions and all personnel in the operational chain of management.

• Under our omnibus agreement, we pay to Noble a fixed fee for the cost of the general and administrative expenses that we anticipate to receive. In addition, to the extent Noble incurs direct, third party out-of-pocket general and administrative costs for our exclusive benefit, we reimburse Noble for such amounts, and we are responsible for directly incurring certain other general and administrative expenses, such as our tax advisors who specialize in master limited partnerships, lawyers and accounting firms.

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.

Liquidation Stage

Upon our liquidation, the partners, including our General Partner, will be entitled to receive liquidating distributions according to their respective capital account balances.

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Agreements with our Affiliates in Connection with the IPO Transactions

We and other parties entered into the various agreements that effected the transactions in connection with the IPO, including the vesting of assets in, and the assumption of liabilities by, us and our subsidiaries, and the application of the proceeds from the IPO. While not the result of arm’s-length negotiations, we believe the terms of all of our initial agreements with Noble and its affiliates are, 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 services. All of the transaction expenses incurred in connection with these transactions, including the expenses associated with transferring assets into our subsidiaries, were paid for with the proceeds from the IPO.

Omnibus Agreement

At the closing of the IPO, we entered into an omnibus agreement with Noble and our General Partner that addresses the following matters:

• our payment of an annual general and administrative fee, initially in the amount of $6.9 million (prorated for the first year of service), for the provision of certain services by Noble and its affiliates;

• our right of first refusal, or ROFR, on existing Noble and future Noble acquired assets and the right to provide certain services;

• our right of first offer, or ROFO, to acquire Noble’s retained interests in each of the DevCos; 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 its assets that occur after the closing of the IPO and for environmental liabilities related to our assets to the extent Noble is not required to indemnify us.

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. The ROFR and ROFO contained in our omnibus agreement will terminate on the earlier of 15 years from the closing of the IPO, the date that Noble no longer controls our General Partner and on the written agreement of all parties.

Payment of general and administrative support fee and reimbursement of expenses. We pay Noble a flat fee, initially in the amount of $6.9 million per year (payable in equal monthly installments and prorated for the first year of service), for the provision of certain general and administrative services for our benefit.

Once per year, Noble will submit a good faith estimate of the general and administrative services fee based on the services that Noble anticipates providing to us during the following year. The board of directors of our General Partner will have the opportunity to review the proposed general and administrative fee for the upcoming year and submit disputes to Noble; provided, however, that the fee will not be increased from the initial $6.9 million per year for the first three years following the closing of the IPO. If Noble and the board of directors of our General Partner are unable to agree on the amount of the general and administrative fee for any year, Noble and the Partnership will submit their calculations of the fee to an independent auditing firm for review. The determination of the independent auditing firm will be final and binding on Noble and the Partnership with respect to all items included in the general and administrative fee.

Under the omnibus agreement, we will also reimburse Noble for all direct, third party out-of-pocket costs incurred by Noble in providing these services for our exclusive benefit. 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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Rights of First Refusal (ROFR). Under the omnibus agreement, Noble has granted us a ROFR on the right to provide midstream services on certain acreage described below and on the right to acquire certain midstream assets. The following table provides a summary of the ROFR assets and ROFR services granted to us by Noble as well as the net acreage covered by our ROFR, to the extent known as of December 31, 2018, granted to us by Noble.

Areas Served	NBLX ROFR Service	Current Status of Asset	ROFR Net Acreage
East Pony (Northern Colorado)	Natural Gas Processing Natural Gas Gathering	Operational	44,000
Eagle Ford Shale	Crude Oil Gathering Natural Gas Gathering Water Services	Operational	35,000
DJ Basin (other than already dedicated)	To the extent not already dedicated: Crude Oil Gathering Natural Gas Gathering Water Services	N/A	79,000
Delaware Basin	Natural Gas Gathering Fresh Water Services	In Progress	108,000
All future-acquired onshore acreage in the United States (outside of the Marcellus Shale)	Crude Oil Gathering Natural Gas Gathering Natural Gas Processing Water Services	N/A	N/A

The consummation and timing of any acquisition by us of the assets or any provision of midstream services subject to the ROFR will depend upon, among other things, Noble’s decision to sell any of the assets subject to the ROFR or Noble’s decision to obtain midstream services in the acreage or areas subject to 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 or expansions of our services pursuant to our ROFR.

Rights of First Offer (ROFO). Under the omnibus agreement, Noble has granted us a ROFO with respect to its retained interests in the DevCos through which we conduct our midstream services. Pursuant to our ROFO, before Noble can offer any of its retained interests in our DevCos to any third party, Noble must allow us to make an offer to purchase these interests. We believe that the ROFO on Noble’s retained interests in our DevCos will provide us an opportunity to develop organic growth with potentially lower development capital costs. We are under no obligation to purchase any of Noble’s retained interests in our DevCos, and Noble is only under an obligation to permit us to make an offer on these interests to the extent that Noble elects to sell these midstream assets to a third party.

The consummation and timing of any acquisition by us of the interests covered by our ROFO will depend upon, among other things, Noble’s decision to sell any of the interests covered by the ROFO 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 ROFO.

Indemnification. Under the omnibus agreement, Noble will indemnify us, subject to certain deductibles, for all known and certain unknown environmental liabilities that are associated with the ownership or operation of our assets and due to occurrences before the closing of the IPO. 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 third anniversary of the closing of the IPO, and will be subject to an aggregate deductible of $500,000 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 the IPO;

• 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 the IPO, which will be subject to an aggregate deductible of $500,000 before we are entitled to indemnification (other than currently pending legal actions, which are not subject to a deductible);

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• 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 the IPO; and

• all tax liabilities attributable to the assets contributed to us arising prior to the closing of the IPO or otherwise related to Noble’s contribution of those assets to us in connection with the IPO.

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 the IPO 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.

Operational Services and Secondment Agreement

We and our General Partner also entered into an operational services and secondment agreement with Noble setting forth the operational services arrangements described below. Noble seconds certain of its operational, construction, design and management employees and contractors to our General Partner, the Partnership and the Partnership’s subsidiaries (collectively the “Partnership Parties”) to provide management, maintenance and operational functions with respect to our assets. During their period of secondment, the seconded personnel will be under the direct management and supervision of the Partnership Parties.

The Partnership Parties will reimburse Noble for the cost of the seconded employees and contractors, including their wages and benefits. If a seconded employee or contractor does not devote 100% of his or her time to providing services to the Partnership Parties, then we will reimburse Noble for only a prorated portion of such employee’s overall wages and benefits, and the costs associated with contractors based on the percentage of the employee’s or contractor’s time spent working for the Partnership Parties. The Partnership Parties will reimburse Noble on a monthly basis or at other intervals that Noble and the General Partner may agree from time to time.

The operational services and secondment agreement has an initial term of 15 years and will automatically extend for successive renewal terms of one year each, unless terminated by either party upon at least 30 days’ prior written notice before the end of the initial term or any renewal term. In addition, the Partnership Parties may terminate the agreement at any time upon written notice stating the date of termination or reduce the level of services under the agreement at any time upon 30 days’ prior written notice.

Commercial Agreements

We have long-term agreements with Noble for the provision of midstream services. Each of our commercial agreements with Noble covering its DJ Basin acreage was originally entered into January 1, 2015 and expires in 2030. As our third party customer took its interest in our commercial agreements by assignment from Noble, its dedication for crude oil and water-related services will expire in 2030. Each of our commercial agreements with Noble covering its Delaware Basin acreage was originally entered into in the summer of 2016 and expires in 2032. Upon the expiration of the initial term, each agreement will automatically renew for subsequent one-year periods unless terminated by either us or our customer no later than 90 days prior to the end of the initial term or any subsequent one-year term thereafter. Our commercial agreements are subject to existing dedications and provide generally that our dedications will run with the land and be binding on any transferee.

Insurance

Captive insurance entities controlled by Noble provide limited third party liability, property and business interruption insurance to the Partnership at commercially competitive rates. The Partnership and Noble also utilize unaffiliated insurance carriers to provide third party liability, property and business interruption insurance in excess of the captive entities’ retentions. Additionally, director and officer insurance for the Partnership is provided as a part of Noble’s third party director and officer insurance policy.

Director Independence

Our disclosures in Item 10. Directors, Executive Officers and Corporate Governance are incorporated herein by reference.

Procedures for Review, Approval and Ratification of Related Person Transactions

The board of directors of our General Partner adopted a code of business conduct and ethics in connection with the completion of the IPO that provides 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.

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The code of business conduct and ethics provides 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 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.

Item 14.  Principal Accounting Fees and Services

The table below sets forth the aggregate fees and expenses for the years ended December 31, 2017 and December 31, 2018 for professional services performed by our independent registered public accounting firm KPMG LLP:

	Year Ended December 31,
(in thousands)	2018		2017
Audit Fees(1)	$	1,350	$	1,060
Audit-Related Fees	—		—
Tax Fees	—		—
All Other Fees	—		—
Total Fees	$	1,350	$	1,060

⁽¹⁾  Audit fees consist of the aggregate fees billed or expected to be billed for professional services rendered for (i) the audit of our annual financial statements included in our Annual Report and a review of our quarterly financial statements included in our Quarterly Reports on Form 10-Q, (ii) the audit of internal control over financial reporting, (iii) the filing of our registration statements for equity securities offerings, (iv) research necessary to comply with generally accepted accounting principles, and (v) other filings with the SEC, including consents, comfort letters, and comment letters.

Our audit committee of the board of directors of our General Partner has 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 has adopted a pre-approval policy with respect to services which may be performed by KPMG LLP. This policy lists specific audit-related and tax services as well as any other services that KPMG LLP is authorized to perform and sets out specific dollar limits for each specific service, which may not be exceeded without additional audit committee authorization. The audit committee receives quarterly reports on the status of expenditures pursuant to that pre-approval policy. The audit committee reviews the policy at least annually in order to approve services and limits for the current year. Any service that is not clearly enumerated in the policy must receive specific pre-approval by the audit committee. For the year ended December 31, 2018, the audit committee approved 100% of the services described above pursuant to the above policy.

The audit committee of the board of directors of our General Partner has approved the appointment of KPMG LLP as independent registered public accounting firm to conduct the audit of the Partnership’s consolidated financial statements for the year ended December 31, 2019.

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PART IV

Item 15.  Exhibits, Financial Statement Schedules

(a)       The following documents are filed as a part of this report:

(1) Financial Statements: The financial statements required to be filed by this Item 15 are set forth in Item 8. Financial Statements and Supplementary Data.

(3) Exhibits: The exhibits required to be filed by this Item 15 are set forth in the Index to Exhibits accompanying this report.

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Index to Exhibits

Exhibit Number	Exhibit
2.1	Advantage Pipeline Holdings LLC Subscription Agreement, dated February 12, 2017, by and among Advantage Pipeline Holdings LLC, Trinity River DevCo LLC and Plains Pipeline, L.P. (filed as Exhibit 2.1 to the Registrant’s Annual Report on Form 10-K (File No. 001-37640) filed February 14, 2017 and incorporated herein by reference)
2.2	Member Interest Purchase and Sale Agreement, dated December 12, 2017, by and between Black Diamond Gathering LLC and Saddle Butte Pipeline II, LLC (filed as Exhibit 2.1 to the Registrant’s Current Report of Form 8-K (Date of Event: December 12, 2017) filed December 12, 2017 and incorporated herein by reference).
2.3	Contribution Agreement, dated June 20, 2017, by and among the Registrant, Noble Midstream GP LLC, Noble Midstream Services, LLC, NBL Midstream, LLC and Blanco River DevCo GP LLC (filed as Exhibit 2.1 to the Registrant’s Current Report on Form 8-K (Date of Event: June 20, 2017) filed June 26, 2017 and incorporated herein by reference).
3.1	Certificate of Limited Partnership of the Registrant (filed as Exhibit 3.1 to the Registrant’s Registration Statement on Form S-1 (Registration No. 333-207560) filed October 22, 2015 and incorporated herein by reference).
3.2	Amendment to the Certificate of Limited Partnership of the Registrant (filed as Exhibit 3.2 to the Registrant’s Registration Statement on Form S-1 (Registration No. 333-207560) filed October 22, 2015 and incorporated herein by reference).
3.3	Amendment to the Certificate of Limited Partnership of the Registrant (filed as Exhibit 3.3 to Amendment No. 1 to the Registrant’s Registration Statement on Form S-1 (Registration No. 333-207560) filed November 6, 2015 and incorporated herein by reference).
3.4	First Amended and Restated Agreement of Limited Partnership of the Registrant (filed as Exhibit 3.1 to the Registrant’s Current Report on Form 8-K (Date of Event: September 14, 2016) filed September 20, 2016 and incorporated herein by reference).
4.1	Registration Rights Agreement, dated June 26, 2017, by and among the Registrant and the Purchasers named therein (filed as Exhibit 4.1 to the Registrant’s Current Report on Form 8-K (Date of Event: June 26, 2017) filed June 26, 2017 and incorporated herein by reference).
10.1	Contribution, Conveyance and Assumption Agreement dated September 20, 2016, by and among the Registrant, Noble Midstream GP LLC, Noble Energy, Inc., Noble Midstream Services, LLC, NBL Midstream, LLC, NBL Midstream Holdings, LLC , Colorado River DevCo GP LLC, Green River DevCo GP LLC, Gunnison River DevCo GP LLC, Laramie River DevCo GP LLC, San Juan River DevCo GP LLC, Blanco River DevCo LP and Blanco River DevCo GP LLC. (filed as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K (Date of Event: September 14, 2016) filed September 20, 2016 and incorporated herein by reference).
10.2*	Registrant’s 2016 Long-Term Incentive Plan (filed as Exhibit 10.5 to the Registrant’s Current Report on Form 8-K (Date of Event: September 14, 2016) filed September 20, 2016 and incorporated herein by reference).
10.3	Omnibus Agreement dated September 20, 2016, by and among Noble Energy, Inc., Noble Energy Services, Inc., Noble Midstream Services, LLC, NBL Midstream, LLC, Noble Midstream GP LLC and the Registrant (filed as Exhibit 10.2 to the Registrant’s Current Report on Form 8-K (Date of Event: September 14, 2016) filed September 20, 2016 and incorporated herein by reference).
10.3.1	Limited Waiver to Omnibus Agreement dated February 14, 2017, by and among the Registrant, Noble Midstream GP LLC, Noble Midstream Services, LLC, Noble Energy, Inc., Noble Energy Services, Inc. and NBL Midstream LLC (filed as Exhibit 10.4 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2017 filed May 2, 2017 and incorporated herein by reference).

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10.3.2	First Amendment to the Limited Waiver to Omnibus Agreement dated June 23, 2017, by and among the Registrant, Noble Energy, Inc., Noble Energy Services, Inc., NBL Midstream, LLC, Noble Midstream Services, LLC and Noble Midstream GP LLC, (filed as Exhibit 10.2 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2017 filed August 3, 2017 and incorporated herein by reference).
10.3.3***	Amendment to Limited Waiver to Omnibus Agreement dated February 7, 2019, by and among the Registrant, Noble Midstream GP LLC, Noble Midstream Services, LLC, Noble Energy, Inc., Noble Energy Services, Inc. and NBL Midstream LLC.
10.4	Operational Services and Secondment Agreement dated September 20, 2016, by and among Noble Energy, Inc., Noble Energy Services, Inc., Noble Midstream GP LLC and the Registrant (filed as Exhibit 10.3 to the Registrant’s Current Report on Form 8-K (Date of Event: September 14, 2016) filed September 20, 2016 and incorporated herein by reference).
10.5	Credit Agreement dated September 20, 2016, by and among the Registrant, as the parent, and Noble Midstream Services, LLC, as the Borrower, the subsidiaries of the Borrower identified therein, JPMorgan Chase Bank, N.A., and the other lenders party thereto (filed as Exhibit 10.4 to the Registrant’s Current Report on Form 8-K (Date of Event: September 14, 2016) filed September 20, 2016 and incorporated herein by reference).
10.5.1	First Amendment to Credit Agreement, dated February 12, 2017, to Credit Agreement dated September 20, 2016, by and among the Registrant, as the parent, and Noble Midstream Services, LLC, as the Borrower, the subsidiaries of the Borrower identified therein, JPMorgan Chase Bank, N.A., and the other lenders party thereto (filed as Exhibit 10.5.1 to the Registrant’s Annual Report on Form 10-K (File No. 001-37640) filed February 14, 2017 and incorporated herein by reference).
10.5.2	Second Amendment to Credit Agreement, dated January 31, 2018, to Credit Agreement dated September 20, 2016, by and among the Registrant, as the parent, and Noble Midstream Services, LLC, as the Borrower, the subsidiaries of the Borrower identified therein, JPMorgan Chase Bank, N.A., and the other lenders party thereto (filed as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K (Date of Event: January 31, 2018) filed February 2, 2018 and incorporated herein by reference).
10.5.3	Amendment and Restatement Agreement, dated March 9, 2018, to Credit Agreement dated September 20, 2016, by and among the Partnership, as the parent, Noble Midstream Services, LLC, as the Borrower, the subsidiaries of the Borrower identified therein, JPMorgan Chase Bank, N.A., and the other lenders party thereto (filed as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K (Date of Event: March 9, 2018) filed March 12, 2018 and incorporated by reference).
10.6	Second Amended and Restated Agreement Terms and Conditions Relating to Gas Gathering Services (filed as Exhibit 10.6 to Amendment No. 5 to the Registrant’s Registration Statement on Form S-1 (Registration No. 333-207560) filed July 22, 2016 and incorporated herein by reference).
10.6.1†	Second Amended and Restated Gas Gathering Agreement, Agreement Addendum 01, effective as of March 31, 2016, among Noble Energy, Inc. and Colorado River DevCo LP (filed as Exhibit 10.7.1 to Amendment No. 5 to the Registrant’s Registration Statement on Form S-1 (Registration No. 333-207560) filed July 22, 2016 and incorporated herein by reference).
10.6.1.1	Amendment 01 to that certain Second Amended and Restated Gas Gathering Agreement, together with Agreement Addendum 01, effective as of September 1, 2016, among Noble Energy, Inc. and Colorado River DevCo LP (filed as Exhibit 10.7.2 to Amendment No. 7 to the Registrant’s Registration Statement on Form S-1 (Registration No. 333-207560) filed September 6, 2016 and incorporated herein by reference).
10.6.2†	Second Amended and Restated Gas Gathering Agreement, Agreement Addendum 03, effective as of March 31, 2016, among Noble Energy, Inc. and Green River DevCo LP (filed as Exhibit 10.8.1 to Amendment No. 5 to the Registrant’s Registration Statement on Form S‑1 (Registration No. 333-207560) filed July 22, 2016 and incorporated herein by reference).
10.6.2.1	Amendment 01 to that certain Second Amended and Restated Gas Gathering Agreement, together with Agreement Addendum 03, effective as of September 1, 2016, among Noble Energy, Inc. and Green River DevCo LP (filed as Exhibit 10.8.1.1 to Amendment No. 7 to the Registrant’s Registration Statement on Form S-1 (Registration No. 333-207560) filed September 6, 2016 and incorporated herein by reference).

129

10.6.2.2†	Amendment 02 to that certain Second Amended and Restated Gas Gathering Agreement, together with Agreement Addendum 03 and Amendment 01, effective as of July 1, 2018, among Noble Energy, Inc. and Green River DevCo LP (filed as Exhibit 10.4 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2018 filed on November 1, 2018 and incorporated herein by reference).
10.6.3	Second Amended and Restated Gas Gathering Agreement, Agreement Addendum XX, effective as of March 31, 2016, among Noble Energy, Inc. and Noble Midstream Services, LLC (filed as Exhibit 10.8.2 to Amendment No. 5 to the Registrant’s Registration Statement on Form S-1 (Registration No. 333-207560) filed July 22, 2016 and incorporated herein by reference).
10.7	Third Amended and Restated Agreement Terms and Conditions Relating to Crude Oil Treating Services (filed as Exhibit 10.9 to Amendment No. 7 to the Registrant’s Registration Statement on Form S-1 (Registration No. 333-207560) filed September 6, 2016 and incorporated herein by reference).
10.7.1†	Third Amended and Restated Crude Oil Treating Agreement, Agreement Addendum 01, effective as of March 31, 2016, among Noble Energy, Inc. and Colorado River DevCo LP (filed as Exhibit 10.10.1 to Amendment No. 7 to the Registrant’s Registration Statement on Form S-1 (Registration No. 333-207560) filed September 6, 2016 and incorporated herein by reference).
10.7.2†	Third Amended and Restated Crude Oil Treating Agreement, Agreement Addendum 02, effective as of March 31, 2016, among Noble Energy, Inc. and Colorado River DevCo LP (filed as Exhibit 10.10.2 to Amendment No. 7 to the Registrant’s Registration Statement on Form S-1 (Registration No. 333-207560) filed September 6, 2016 and incorporated herein by reference).
10.8	Second Amended and Restated Agreement Terms and Conditions Relating to Produced Water Services (filed as Exhibit 10.11 to Amendment No. 5 to the Registrant’s Registration Statement on Form S-1 (Registration No. 333-207560) filed July 22, 2016 and incorporated herein by reference).
10.8.1†	Second Amended and Restated Produced Water Services Agreement, Agreement Addendum 01, effective as of March 31, 2016, among Noble Energy, Inc. and Colorado River DevCo LP (filed as Exhibit 10.12.2 to Amendment No. 5 to the Registrant’s Registration Statement on Form S-1 (Registration No. 333-207560) filed July 22, 2016 and incorporated herein by reference).
10.8.1.1	Amendment 01 to that certain Second Amended and Restated Produced Water Services Agreement, together with Agreement Addendum 01, effective as of September 1, 2016, among Noble Energy, Inc. and Colorado River DevCo LP (filed as Exhibit 10.12.3 to Amendment No. 7 to the Registrant’s Registration Statement on Form S-1 (Registration No. 333-207560) filed September 6, 2016 and incorporated herein by reference).
10.8.2†	Second Amended and Restated Produced Water Services Agreement, Agreement Addendum 02, effective as of March 31, 2016, among Noble Energy, Inc. and San Juan River DevCo LP (filed as Exhibit 10.13.1 to Amendment No. 5 to the Registrant’s Registration Statement on Form S-1 (Registration No. 333-207560) filed July 22, 2016 and incorporated herein by reference).
10.8.2.1	Amendment 01 to that certain Second Amended and Restated Produced Water Services Agreement, together with Agreement Addendum 02, effective as of September 1, 2016, among Noble Energy, Inc. and San Juan River DevCo LP (filed as Exhibit 10.13.2 to Amendment No. 7 to the Registrant’s Registration Statement on Form S-1 (Registration No. 333-207560) filed September 6, 2016 and incorporated herein by reference).
10.8.3	Second Amended and Restated Produced Water Services Agreement, Agreement Addendum 03, effective as of March 31, 2016, among Noble Energy, Inc. and Green River DevCo LP (filed as Exhibit 10.14.1 to Amendment No. 5 to the Registrant’s Registration Statement on Form S-1 (Registration No. 333-207560) filed July 22, 2016 and incorporated herein by reference).
10.8.3.1	Amendment 01 to that certain Second Amended and Restated Produced Water Services Agreement, together with Agreement Addendum 03, effective as of September 1, 2016, among Noble Energy, Inc. and Green River DevCo LP (filed as Exhibit 10.14.2 to Amendment No. 7 to the Registrant’s Registration Statement on Form S-1 (Registration No. 333-207560) filed September 6, 2016 and incorporated herein by reference).

130

10.8.3.2†	Second Amended and Restated Produced Water Services Agreement, Agreement Addendum 04, effective as of March 31, 2016, among Noble Energy, Inc. and Gunnison River DevCo LP (filed as Exhibit 10.15.1 to Amendment No. 5 to the Registrant’s Registration Statement on Form S-1 (Registration No. 333-207560) filed July 22, 2016 and incorporated herein by reference).
10.8.4	Second Amended and Restated Produced Water Services Agreement, Agreement Addendum 04, effective as of March 31, 2016, among Noble Energy, Inc. and Gunnison River DevCo LP (filed as Exhibit 10.15.1 to Amendment No. 5 to the Registrant’s Registration Statement on Form S-1 (Registration No. 333-207560) filed July 22, 2016 and incorporated herein by reference).
10.8.4.1	Amendment 01 to that certain Second Amended and Restated Produced Water Services Agreement, together with Agreement Addendum 04, effective as of September 1, 2016, among Noble Energy, Inc. and Gunnison River DevCo LP (filed as Exhibit 10.15.2 to Amendment No. 7 to the Registrant’s Registration Statement on Form S-1 (Registration No. 333-207560) filed September 6, 2016 and incorporated herein by reference).
10.8.5	Second Amended and Restated Produced Water Services Agreement, Agreement Addendum 05, effective as of March 31, 2016, among Noble Energy, Inc. and Laramie River DevCo LP (filed as Exhibit 10.16.1 to Amendment No. 5 to the Registrant’s Registration Statement on Form S-1 (Registration No. 333-207560) filed July 22, 2016 and incorporated herein by reference).
10.8.5.1	Amendment 01 to that certain Second Amended and Restated Produced Water Services Agreement, together with Agreement Addendum 05, effective as of September 1, 2016, among Noble Energy, Inc. and Laramie River DevCo LP (filed as Exhibit 10.16.1.1 to Amendment No. 7 to the Registrant’s Registration Statement on Form S-1 (Registration No. 333-207560) filed September 6, 2016 and incorporated herein by reference).
10.8.6	Second Amended and Restated Produced Water Services Agreement, Agreement Addendum XX, effective as of March 31, 2016, among Noble Energy, Inc. and Noble Midstream Services, LLC (filed as Exhibit 10.16.2 to Amendment No. 5 to the Registrant’s Registration Statement on Form S-1 (Registration No. 333-207560) filed July 22, 2016 and incorporated herein by reference).
10.9	Texas Agreement Terms and Conditions Relating to Produced Water Services (filed as Exhibit 10.37 to Amendment No. 7 to the Registrant’s Registration Statement on Form S-1 (Registration No. 333-207560) filed September 6, 2016 and incorporated herein by reference).
10.9.1†	Texas Produced Water Services Agreement, Agreement Addendum 01, effective as of September 1, 2016, between Rosetta Resources Operating LP and Blanco River DevCo LP (filed as Exhibit 10.38 to Amendment No. 7 to the Registrant’s Registration Statement on Form S-1 (Registration No. 333-207560) filed September 6, 2016 and incorporated herein by reference).
10.10	Second Amended and Restated Agreement Terms and Conditions Relating to Fresh Water Services (filed as Exhibit 10.17 to Amendment No. 5 to the Registrant’s Registration Statement on Form S-1 (Registration No. 333-207560) filed July 22, 2016 and incorporated herein by reference).
10.10.1†	Second Amended and Restated Fresh Water Services Agreement, Agreement Addendum 01, effective as of March 31, 2016, among Noble Energy, Inc. and Colorado River DevCo LP (filed as Exhibit 10.18.1 to Amendment No. 5 to the Registrant’s Registration Statement on Form S-1 (Registration No. 333-207560) filed July 22, 2016 and incorporated herein by reference).
10.10.1.1	Amendment 01 to that certain Second Amended and Restated Fresh Water Services Agreement, Agreement Addendum 01, effective as of March 31, 2016, among Noble Energy, Inc. and Colorado River DevCo LP (filed as Exhibit 10.18.2 to Amendment No. 7 to the Registrant’s Registration Statement on Form S-1 (Registration No. 333-207560) filed September 6, 2016 and incorporated herein by reference).
10.10.1.2†	Amendment 02 to that certain Second Amended and Restated Fresh Water Services Agreement, together with Agreement Addendum 03 and Amendment 01, effective as of July 1, 2018, among Noble Energy, Inc. and Green River DevCo LP (filed as Exhibit 10.7 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2018 filed on November 1, 2018 and incorporated herein by reference).
10.10.2†	Second Amended and Restated Fresh Water Services Agreement, Agreement Addendum 02, effective as of March 31, 2016, among Noble Energy, Inc. and San Juan River DevCo LP (filed as Exhibit 10.19.1 to Amendment No. 5 to the Registrant’s Registration Statement on Form S-1 (Registration No. 333-207560) filed July 22, 2016 and incorporated herein by reference).

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10.10.2.1	Amendment 01 to that certain Second Amended and Restated Fresh Water Services Agreement, together with Agreement Addendum 02, effective as of September 1, 2016, among Noble Energy, Inc. and San Juan River DevCo LP (filed as Exhibit 10.19.2 to Amendment No. 7 to the Registrant’s Registration Statement on Form S-1 (Registration No. 333-207560) filed September 6, 2016 and incorporated herein by reference).
10.10.3†	Second Amended and Restated Fresh Water Services Agreement, Agreement Addendum 03, effective as of March 31, 2016, among Noble Energy, Inc. and Green River DevCo LP (filed as Exhibit 10.20.1 to Amendment No. 5 to the Registrant’s Registration Statement on Form S-1 (Registration No. 333-207560) filed July 22, 2016 and incorporated herein by reference).
10.10.3.1	Amendment 01 to that certain Second Amended and Restated Fresh Water Services Agreement, together with Agreement Addendum 03, effective as of September 1, 2016, among Noble Energy, Inc. and Green River DevCo LP (filed as Exhibit 10.20.2 to Amendment No. 7 to the Registrant’s Registration Statement on Form S-1 (Registration No. 333-207560) filed September 6, 2016 and incorporated herein by reference).
10.10.3.2†	Amendment 02 to that certain Second Amended and Restated Fresh Water Services Agreement, together with Agreement Addendum 03 and Amendment 01, effective as of July 1, 2018, among Noble Energy, Inc. and Green River DevCo LP (filed as Exhibit 10.5 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2018 filed on November 1, 2018 and incorporated herein by reference).
10.10.4	Second Amended and Restated Fresh Water Services Agreement, Agreement Addendum 04, effective as of March 31, 2016, among Noble Energy, Inc. and Gunnison River DevCo LP (filed as Exhibit 10.21.1 to Amendment No. 5 to the Registrant’s Registration Statement on Form S-1 (Registration No. 333-207560) filed July 22, 2016 and incorporated herein by reference).
10.10.4.1	Amendment 01 to that certain Second Amended and Restated Fresh Water Services Agreement, together with Agreement Addendum 04, effective as of September 1, 2016, among Noble Energy, Inc. and Gunnison River DevCo LP (filed as Exhibit 10.21.2 to Amendment No. 7 to the Registrant’s Registration Statement on Form S-1 (Registration No. 333-207560) filed September 6, 2016 and incorporated herein by reference).
10.10.5	Second Amended and Restated Fresh Water Services Agreement, Agreement Addendum 05, effective as of March 31, 2016, among Noble Energy, Inc. and Laramie River DevCo LP (filed as Exhibit 10.22.1 to Amendment No. 5 to the Registrant’s Registration Statement on Form S-1 (Registration No. 333-207560) filed July 22, 2016 and incorporated herein by reference).
10.10.5.1	Amendment 01 to that certain Second Amended and Restated Fresh Water Services Agreement, together with Agreement Addendum 05, effective as of September 1, 2016, among Noble Energy, Inc. and Laramie River DevCo LP (filed as Exhibit 10.22.1.1 to Amendment No. 7 to the Registrant’s Registration Statement on Form S-1 (Registration No. 333-207560) filed September 6, 2016 and incorporated herein by reference).
10.10.6	Second Amended and Restated Fresh Water Services Agreement, Agreement Addendum XX, effective as of March 31, 2016, among Noble Energy, Inc. and Noble Midstream Services, LLC (filed as Exhibit 10.22.2 to Amendment No. 5 to the Registrant’s Registration Statement on Form S-1 (Registration No. 333-207560) filed July 22, 2016 and incorporated herein by reference).
10.11	Second Amended and Restated Terms and Conditions Relating to Crude Oil Gathering Services (filed as Exhibit 10.23 to Amendment No. 5 to the Registrant’s Registration Statement on Form S-1 (Registration No. 333-207560) filed July 22, 2016 and incorporated herein by reference).
10.11.1†	Second Amended and Restated Crude Oil Gathering Agreement, Agreement Addendum 01, effective as of March 31, 2016, among Noble Energy, Inc. and Colorado River DevCo LP (filed as Exhibit 10.24.1 to Amendment No. 5 to the Registrant’s Registration Statement on Form S-1 (Registration No. 333-207560) filed July 22, 2016 and incorporated herein by reference).
10.11.1.1	Amendment 01 to that certain Second Amended and Restated Crude Oil Gathering Agreement, together with Agreement Addendum 01, effective as of September 1, 2016, among Noble Energy, Inc. and Colorado River DevCo LP (filed as Exhibit 10.24.2 to Amendment No. 7 to the Registrant’s Registration Statement on Form S-1 (Registration No. 333-207560) filed September 6, 2016 and incorporated herein by reference).
10.11.2†	Second Amended and Restated Crude Oil Gathering Agreement, Agreement Addendum 02, effective as of March 31, 2016, among Noble Energy, Inc. and Colorado River DevCo LP (filed as Exhibit 10.25.1 to Amendment No. 5 to the Registrant’s Registration Statement on Form S-1 (Registration No. 333-207560) filed July 22, 2016 and incorporated herein by reference).

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10.11.2.1	Amendment 01 to that certain Second Amended and Restated Crude Oil Gathering Agreement, together with Agreement Addendum 02, effective as of September 1, 2016, among Noble Energy, Inc. and Colorado River DevCo LP (filed as Exhibit 10.25.2 to Amendment No. 7 to the Registrant’s Registration Statement on Form S-1 (Registration No. 333-207560) filed September 6, 2016 and incorporated herein by reference).
10.11.3	Second Amended and Restated Crude Oil Gathering Agreement, Agreement Addendum 03, effective as of March 31, 2016, among Noble Energy, Inc. and Green River DevCo LP (filed as Exhibit 10.26.1 to Amendment No. 5 to the Registrant’s Registration Statement on Form S-1 (Registration No. 333-207560) filed July 22, 2016 and incorporated herein by reference).
10.11.3.1	Amendment 01 to that certain Second Amended and Restated Crude Oil Gathering Agreement, together with Agreement Addendum 03, effective as of September 1, 2016, among Noble Energy, Inc. and Green River DevCo LP (filed as Exhibit 10.26.2 to Amendment No. 7 to the Registrant’s Registration Statement on Form S-1 (Registration No. 333-207560) filed September 6, 2016 and incorporated herein by reference).
10.11.3.2†	Amendment 02 to that certain Second Amended and Restated Crude Oil Gathering Agreement, together with Agreement Addendum 03 and Amendment 01, effective as of July 1, 2018, among Noble Energy, Inc. and Green River DevCo LP (filed as Exhibit 10.3 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2018 filed on November 1, 2018 and incorporated herein by reference).
10.11.4	Second Amended and Restated Crude Oil Gathering Agreement, Agreement Addendum 04, effective as of March 31, 2016, among Noble Energy, Inc. and Gunnison River DevCo LP (filed as Exhibit 10.27.1 to Amendment No. 5 to the Registrant’s Registration Statement on Form S-1 (Registration No. 333-207560) filed July 22, 2016 and incorporated herein by reference).
10.11.4.1	Amendment 01 to that certain Second Amended and Restated Crude Oil Gathering Agreement, together with Agreement Addendum 04, effective as of September 1, 2016, among Noble Energy, Inc. and Gunnison River DevCo LP (filed as Exhibit 10.27.2 to Amendment No. 7 to the Registrant’s Registration Statement on Form S-1 (Registration No. 333-207560) filed September 6, 2016 and incorporated herein by reference).
10.11.5	Second Amended and Restated Crude Oil Gathering Agreement, Agreement Addendum 05, effective as of March 31, 2016, among Noble Energy, Inc. and Laramie River DevCo LP (filed as Exhibit 10.28.1 to Amendment No. 5 to the Registrant’s Registration Statement on Form S-1 (Registration No. 333-207560) filed July 22, 2016 and incorporated herein by reference).
10.11.5.1	Amendment 01 to that certain Second Amended and Restated Crude Oil Gathering Agreement, together with Agreement Addendum 05, effective as of September 1, 2016, among Noble Energy, Inc. and Laramie River DevCo LP (filed as Exhibit 10.28.1.1 to Amendment No. 7 to the Registrant’s Registration Statement on Form S-1 (Registration No. 333-207560) filed September 6, 2016 and incorporated herein by reference).
10.11.6	Second Amended and Restated Crude Oil Gathering Agreement, Agreement Addendum XX, effective as of March 31, 2016, among Noble Energy, Inc. and Noble Midstream Services, LLC (filed as Exhibit 10.28.2 to Amendment No. 5 to the Registrant’s Registration Statement on Form S-1 (Registration No. 333-207560) filed July 22, 2016 and incorporated herein by reference).
10.12	Texas Agreement Terms and Conditions Relating to Crude Oil Gathering Services (filed as Exhibit 10.35 to Amendment No. 7 to the Registrant’s Registration Statement on Form S-1 (Registration No. 333-207560) filed September 6, 2016 and incorporated herein by reference).
10.12.1†	Texas Oil Gathering Agreement, Agreement Addendum 01, effective as of September 1, 2016, between Rosetta Resources Operating LP and Blanco River DevCo LP (filed as Exhibit 10.36 to Amendment No. 7 to the Registrant’s Registration Statement on Form S-1 (Registration No. 333-207560) filed September 6, 2016 and incorporated herein by reference).
10.13	First Amended and Restated Agreement of Limited Partnership of Colorado River DevCo LP (filed as Exhibit 10.6 to the Registrant’s Current Report on Form 8-K (Date of Event: September 14, 2016) filed September 20, 2016 and incorporated herein by reference).
10.14	First Amended and Restated Agreement of Limited Partnership of Green River DevCo LP (filed as Exhibit 10.7 to the Registrant’s Current Report on Form 8-K (Date of Event: September 14, 2016) filed September 20, 2016 and incorporated herein by reference).

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10.15	First Amended and Restated Agreement of Limited Partnership of Gunnison River DevCo LP (filed as Exhibit 10.8 to the Registrant’s Current Report on Form 8-K (Date of Event: September 14, 2016) filed September 20, 2016 and incorporated herein by reference).
10.16	First Amended and Restated Agreement of Limited Partnership of San Juan River DevCo LP (filed as Exhibit 10.9 to the Registrant’s Current Report on Form 8-K (Date of Event: September 14, 2016) filed September 20, 2016 and incorporated herein by reference.
10.17	First Amended and Restated Agreement of Limited Partnership of Blanco River DevCo LP (filed as Exhibit 10.10 to the Registrant’s Current Report on Form 8-K (Date of Event: September 14, 2016) filed September 20, 2016 and incorporated herein by reference).
10.18*	Registrant’s Form of Non-Employee Director Restricted Unit Agreement under the Partnership’s 2016 Long-Term Incentive Plan (filed as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K (Date of Event: October 27, 2016) filed November 2, 2016 and incorporated herein by reference).
10.19*	Registrant's Form of Employee Restricted Unit Agreement under the Partnership’s 2016 Long-Term Incentive Plan (filed as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K (Date of Event: January 26, 2017) filed January 26, 2017 and incorporated herein by reference).
10.20*	Registrant's Form of Employee Restricted Unit Agreement [3-Year Cliff Vest] under the Partnership’s 2016 Long-Term Incentive Plan (filed as Exhibit 10.3 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2017 filed on May 2, 2017 and incorporated herein by reference).
10.21	Term Credit Agreement, dated as of July 31, 2018, by and among Noble Midstream Services, LLC, as borrower, the Partnership, as parent, and Toronto Dominion (Texas) LLC and the other lenders party thereto (filed as Exhibit 10.1 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2018 filed on August 3, 2018 and incorporated herein by reference).
10.22	Guarantee Agreement, dated as of July 31, 2018, by and among Noble Midstream Services, LLC, as borrower, the Partnership, as parent, and Toronto Dominion (Texas) LLC and the other lenders party thereto (filed as Exhibit 10.2 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2018 filed on August 3, 2018 and incorporated herein by reference).
21.1***	Subsidiaries
23.1***	Consent of Independent Registered Public Accounting Firm — KPMG LLP
31.1***	Certification of the Company’s Chief Executive Officer Pursuant To Section 302 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 7241).
31.2***	Certification of the Company’s Chief Financial Officer Pursuant To Section 302 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 7241).
32.1***	Certification of the Company’s Chief Executive Officer Pursuant To Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350).
32.2***	Certification of the Company’s Chief Financial Officer Pursuant To Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350).
101.INS	XBRL Instance Document
101.SCH	XBRL Schema Document
101.CAL	XBRL Calculation Linkbase Document
101.LAB	XBRL Label Linkbase Document
101.PRE	XBRL Presentation Linkbase Document
101.DEF	XBRL Definition Linkbase Document

* Management contract or compensatory plan or arrangement required to be filed as an exhibit hereto.

134

† Confidential treatment has been granted for certain portions thereof pursuant to a Confidential Treatment Request filed with the Securities and Exchange Commission. Such provisions have been filed separately with the Securities and Exchange Commission.

** Copies of exhibits will be furnished upon prepayment of 25 cents per page. Requests should be addressed to the Chief Financial Officer, Noble Midstream Partners LP, 1001 Noble Energy Way, Houston, Texas 77070.

*** Filed herewith.

+ Exhibits and schedules have been omitted pursuant to Item 601(b)(2) of Regulation S-K and will be furnished to the Securities and Exchange Commission upon request.

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Item 16. Form 10-K Summary

None.

GLOSSARY

In this report, the following abbreviations are used:

Bbl	Barrel
Bbl/d	Barrels per day
Bpm	Barrels per minute
Btu	British thermal unit
Btu/d	British thermal units per day
CGF	Central gathering facility
CPI	Consumer Price Index
DCF	Distributable cash flow
DevCo	Development company
DJ Basin	Denver-Julesburg Basin
EBITDA	Earnings before interest, taxes, depreciation, and amortization
FASB	Financial Accounting Standards Board
FERC	The Federal Energy Regulatory Commission
GAAP	United States generally accepted accounting principles
GHG	Greenhouse gas emissions
IDP	Integrated development plan
IDRs	Incentive distribution rights
IPO	Initial Public Offering
LIBOR	London Interbank Offered Rate
MBbl/d	Thousand barrels per day
Mcf/d	Thousand cubic feet per day
MMBtu	Million British thermal units
MMBtu/d	Million British thermal units per day
NGL	Natural gas liquids
PPI	Producer Price Index
ROFO	Right of first offer
ROFR	Right of first refusal

136

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

		Noble Midstream Partners LP
		By: Noble Midstream GP, LLC,        its General Partner
Date:	February 19, 2019	By: /s/ Terry R. Gerhart
		Terry R. Gerhart,
		Chief Executive Officer and Director
Date:	February 19, 2019	By: /s/ John F. Bookout, IV
		John F. Bookout, IV,
		Chief Financial Officer
Date:	February 19, 2019	By: /s/ Thomas W. Christensen
		Thomas W. Christensen,
		Chief Accounting Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.

Signature	Title	Date
/s/ Terry R. Gerhart	Chief Executive Officer and Director	February 19, 2019
Terry R. Gerhart	(Principal Executive Officer)
/s/ John F. Bookout, IV	Chief Financial Officer	February 19, 2019
John F. Bookout, IV	(Principal Financial Officer)
/s/ Thomas W. Christensen	Chief Accounting Officer	February 19, 2019
Thomas W. Christensen	(Principal Accounting Officer)
/s/ Kenneth M. Fisher	Chairman of the Board of Directors	February 19, 2019
Kenneth M. Fisher
/s/ Thomas H. Walker	Director	February 19, 2019
Thomas H. Walker
/s/ Brent J. Smolik	Director	February 19, 2019
Brent J. Smolik
/s/ Hallie A. Vanderhider	Director	February 19, 2019
Hallie A. Vanderhider
/s/ Martin Salinas, Jr.	Director	February 19, 2019
Martin Salinas, Jr.
/s/ Andrew E. Viens	Director	February 19, 2019
Andrew E. Viens

137