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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C.  20549
FORM 10-K
 
☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2019
or
☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from          to          
Commission file number: 001-37640
NBLXUPDATEDLOGOA66.JPG
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
 
Trading Symbol(s)
 
Name of each exchange on which registered
Common Units, Representing Limited Partner Interests
 
NBLX
 
The Nasdaq Stock Market LLC
 
 
 
 
(Nasdaq Global Select Market)
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. ☒ Yes ☐ 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. ☐ Yes ☒ 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. ☒ Yes ☐ 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). ☒ Yes ☐ No 
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
☒
Accelerated filer ☐
Non-accelerated filer ☐
Smaller reporting company
☐
Emerging growth company 
☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
 Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).☐ Yes ☒ No
The aggregate market value of the registrant’s Common Units held by non-affiliates of the registrant as of June 30, 2019, the last business day of the registrant’s most recently completed second fiscal quarter was approximately $718.8 million.
The registrant had 90,239,656 Common Units as of January 31, 2020.
DOCUMENTS INCORPORATED BY REFERENCE: None



Table of Contents
 
PART I
Items 1. and 2.
3
Item 1A.
21
Item 1B.
44
Item 3.
44
Item 4.
44
PART II
Item 5.
45
Item 6.
47
Item 7.
48
Item 7A.
66
Item 8.
67
Item 9.
100
Item 9A.
100
Item 9B.
100
PART III
Item 10.
101
Item 11.
106
Item 12.
125
Item 13.
127
Item 14.
130
PART IV
Item 15.
131
Item 16.
140





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 Noble Midstream Partners LP’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 gathering, natural gas gathering and processing, produced water gathering, 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.
All references to “Noble Midstream Partners,” “NBLX,” “the Partnership,” “us,” “our,” “we” or similar expressions, 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 consolidated financial statements have been retrospectively recast for all periods presented to include the historical results of NBL Midstream Holdings (“NBL Holdings”), as the acquisition of NBL Holdings by the Partnership in the Drop-Down and Simplification Transaction (as defined below) represents a transaction between entities under common control and resulted in a change in reporting entity. The selected financial data covering the periods prior to the aforementioned transactions may not necessarily be indicative of the actual results of operations had these entities been operated together during those periods.
For a summary of commonly used industry terms and abbreviations used in this report, see the Glossary.

2

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. Our business activities are conducted through four reportable segments: Gathering Systems (primarily includes crude oil gathering, natural gas gathering and processing, produced water gathering and crude oil sales), Fresh Water Delivery, Investments in Midstream Entities and Corporate. We often refer to the services of our Gathering Systems and Fresh Water Delivery reportable segments collectively as our midstream services.
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:
AREAOFFOCUSMAPA19.JPG
We are Noble’s primary vehicle for midstream operations in the onshore United States. We have acreage dedications spanning approximately 545,000 acres in the DJ Basin (with over 230,000 dedicated acres from Noble and the remaining dedicated acres from various third parties) and approximately 118,000 acres in the Delaware Basin (with 92,000 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 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 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.

3

2019 Developments
Drop-Down and Simplification Transaction
On November 14, 2019, we entered into a Contribution, Conveyance, Assumption and Simplification Agreement with Noble. Pursuant to such agreement, we acquired (i) the remaining 60% limited partner interest in Blanco River DevCo LP, (ii) the remaining 75% limited partner interest in Green River DevCo LP, (iii) the remaining 75% limited partner interest in San Juan River DevCo LP and (iv) all of the issued and outstanding limited liability company interests of NBL Holdings. Additionally, all of the Incentive Distribution Rights (“IDRs”) were converted into common units representing limited partner interests in the Partnership (“Common Units”). The acquisition of the interests and conversion of the IDRs are collectively referred to as the “Drop-Down and Simplification Transaction.” Our financial information has been recast to include the historical results of NBL Holdings for all periods presented. See Item 8. Financial Statements and Supplementary Data – Note 2. Summary of Significant Accounting Policies and Basis of Presentation for a detailed discussion. The total consideration paid by the Partnership for the Drop-Down and Simplification Transaction was $1.6 billion, which consisted of $670 million in cash and 38,455,018 Common Units issued to Noble.
In the Drop-Down and Simplification Transaction, we acquired essentially all of Noble’s remaining midstream assets. As a result, we have enhanced our operational synergies and increased economic alignment in Noble’s growth basins, which lowers our cost of capital and supports strategic long-term growth and value creation.
The midstream assets we acquired include the Keota and Lilli gas processing plants and associated gas gathering pipelines in the East Pony IDP area of the DJ Basin (the “East Pony IDP”). These assets mark the Partnership’s first entry into DJ Basin gas processing. With the need for incremental gas processing capacity in the DJ Basin, the Keota and Lilli plants provide an additional opportunity for us to grow our third-party business. Additionally, we acquired the legacy Clayton Williams pipeline system, which includes more than 300 miles of oil, gas, and produced water gathering pipelines. These pipelines service Noble’s central and southern Delaware Basin positions and will provide additional opportunities to drive capital efficiency through new well connections and secure third-party dedications.
2019 Private Placement
On November 14, 2019, we entered into a Common Unit Purchase Agreement with certain institutional investors to sell 12,077,295 Common Units in a private placement for gross proceeds of approximately $250 million (the “2019 Private Placement”). Net proceeds totaled approximately $242.9 million, after deducting offering expenses of approximately $7.1 million. The 2019 Private Placement closed on November 21, 2019. Proceeds from the 2019 Private Placement were utilized to fund a portion of the cash consideration for the Drop-Down and Simplification Transaction.
Investment Activity
During 2019, we significantly expanded our strategic relationships and investments in the long-haul pipeline business.
On January 31, 2019, we exercised and closed our option with EPIC Midstream Holdings, LP (“EPIC”) to acquire a 15% interest in EPIC Y-Grade, LP (“EPIC Y-Grade”). During 2019, we made capital contributions to EPIC Y-Grade of $169.1 million.
On January 31, 2019, we exercised our option to acquire an interest in EPIC Crude Holdings, LP (“EPIC Crude”). On March 8, 2019, we closed our option with EPIC to acquire the 30% interest in EPIC Crude. During 2019, we made capital contributions to EPIC Crude of $351.2 million.
On February 7, 2019, we executed definitive agreements with Salt Creek Midstream LLC (“Salt Creek”) and completed the formation of Delaware Crossing LLC (“Delaware Crossing”). We own a 50% interest in Delaware Crossing. During 2019, we made capital contributions to Delaware Crossing of $70.3 million.
Saddlehorn Transportation Commitment and Investment Option
Our affiliate, Black Diamond Gathering LLC (“Black Diamond”) has entered into a strategic relationship with Saddlehorn Pipeline Company, LLC (“Saddlehorn”). Saddlehorn is jointly owned by affiliates of Magellan Midstream Partners, L.P. (“Magellan”), Plains All American Pipeline, L.P. (“Plains”) and Western Midstream Partners, LP (“Western Midstream”). The Saddlehorn pipeline is currently capable of transporting approximately 190 MBbl/d of crude oil and condensate from the DJ Basin and the Powder River Basin to storage facilities in Cushing, Oklahoma owned by Magellan and Plains. With the recent successful open season, the Saddlehorn pipeline will be expanded by 100 MBbl/d, to a new total capacity of 290 MBbl/d. The higher capacity is expected to be available in late 2020 following the addition of incremental pumping and storage capabilities.
As part of the strategic relationship, Black Diamond and Noble entered into long-term firm transportation commitments with Saddlehorn. Black Diamond received an option to acquire an ownership interest of up to 20% in Saddlehorn. Black Diamond’s investment option was scheduled to expire in April 2020.

4

In February 2020, Black Diamond exercised its option, effective February 1, 2020, to acquire a 20% ownership interest in Saddlehorn for $155 million, $84 million net to the Partnership. After Black Diamond’s purchase, with Magellan and Plains each selling a 10% interest, Magellan and Plains each own a 30% membership interest and Black Diamond and Western Midstream each own a 20% membership interest in Saddlehorn. Magellan continues to serve as operator of the Saddlehorn pipeline.


5

Organizational Structure
The following diagram depicts our organizational structure as of December 31, 2019.

ORGSTRUCTURE12312019.JPG


6

Our current areas of operation are in the DJ Basin and Delaware Basin. The following table provides a summary of our development areas within each basin, along with our dedicated services and customers as of December 31, 2019.
Company
Areas Served
NBLX Dedicated Service
Customers
Colorado River LLC (1)

Wells Ranch IDP (DJ Basin)


East Pony IDP (DJ Basin)

All Noble DJ Basin Acreage
Crude Oil Gathering
Natural Gas Gathering
Water Services

Crude Oil Gathering

Crude Oil Treating

Noble
San Juan River LLC (1)
East Pony IDP (DJ Basin)
Water Services
Noble
Green River DevCo LLC (1)
Mustang IDP (DJ Basin)
Crude Oil Gathering
Natural Gas Gathering
Water Services
Noble
Laramie River LLC (1)
Greeley Crescent IDP (DJ Basin)
Crude Oil Gathering
Water Services
Noble and Unaffiliated Third Party
Black Diamond Dedication Area (DJ Basin)
Crude Oil Gathering
Crude Oil Sales
Natural Gas Gathering
Noble and Unaffiliated Third Parties
Blanco River LLC (1)
Delaware Basin
Crude Oil Gathering
Natural Gas Gathering
Water Services
Noble and Unaffiliated Third Parties
Gunnison River DevCo LP
Bronco IDP (DJ Basin) (2)
Crude Oil Gathering
Water Services
Noble
Trinity River DevCo LLC
Delaware Basin
Natural Gas Compression
Crude Oil Transmission
Noble and Unaffiliated Third Parties (3)
Dos Rios DevCo LLC
Delaware Basin
Crude Oil Transmission
Y-Grade Transmission
Noble and Unaffiliated Third Parties (3)
Noble Midstream Holdings LLC
East Pony IDP (DJ Basin)
Natural Gas Gathering
Natural Gas Processing
Noble and Unaffiliated Third Parties
Delaware Basin
Crude Oil Gathering
Natural Gas Gathering
Water Services
Noble and Unaffiliated Third Parties
(1) 
On December 31, 2019, the general partner and limited partnership of each of the above companies was merged into a limited liability company (“LLC”).
(2) 
We currently have no midstream infrastructure assets in the Bronco IDP. We have dedications for any of Noble’s future production in this area.
(3) 
The unaffiliated third-party customers are served though investments in which we exert significant influence.
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.


7

Areas of Operation
The following diagram illustrates our infrastructure in the DJ Basin as of December 31, 2019:
DJBASINA02.JPG









8

The following diagram illustrates our infrastructure in the Delaware Basin as of December 31, 2019:
DELAWAREBASINA01.JPG

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 (primarily includes crude oil gathering, natural gas gathering and processing, produced water gathering and crude oil sales), Fresh Water Delivery, Investments in Midstream Entities and Corporate. We often refer to services of our Gathering Systems and Fresh Water Delivery segments collectively as our midstream services. The Investments in Midstream Entities segment includes our investments in Advantage Pipeline, L.L.C. (“Advantage”), Delaware Crossing, EPIC Y-Grade, EPIC Crude and White Cliffs Pipeline L.L.C. (“White Cliffs”). The Corporate segment includes all general Partnership activity not attributable to our operating subsidiaries. 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 83 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 crude oil and deliver this natural gas to Noble for delivery to downstream third parties.
In 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 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 17 miles of pipeline into the Black Diamond Milton Terminal.
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 45 miles of pipeline to the Grand Mesa Pipeline via the Black Diamond Lucerne Terminal and directly to the White Cliffs pipeline system (the “White Cliffs Pipeline”).
To service the Black Diamond dedication area, we gather crude oil meeting pipeline specifications and deliver it through approximately 252 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 126 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 meet pipeline specifications and deliver to downstream pipelines leaving the Delaware Basin.
As part of the Drop-Down and Simplification Transaction, we acquired an approximately 127-mile crude oil gathering system servicing production from acreage in the Delaware Basin. This crude oil gathering system gathers crude oil meeting pipeline specifications from well pad facilities and terminates at various third-party pipeline connection points.
The table below sets forth our crude oil gathering throughput for the dates indicated.
 
Average Daily Throughput (Bbl/d)
 
Year Ended December 31,
 
2019
 
2018
 
2017
DJ Basin
182,121

 
143,095

 
61,864

Delaware Basin
49,842

 
34,032

 
7,385

Crude Oil Treating
We also operate a crude oil treating facility that services each of the IDP areas and additional wells outside of these areas. Crude oil is delivered to the facility 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 facility, 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.

10

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,
 
2019
 
2018
 
2017
Producing Vertical Wells
1,001

 
1,257

 
1,753

Producing Horizontal Wells
339

 
406

 
471

Natural Gas Gathering
Our natural gas infrastructure assets in the Wells Ranch IDP consist of the Wells Ranch CGF and an approximately 54-mile natural gas pipeline system. This natural gas gathering system 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. We deliver the natural gas for further processing by third parties. Our Wells Ranch CGF also 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.
Our natural gas infrastructure in the Mustang IDP consists of an approximately 15-mile natural gas pipeline system. This natural gas gathering system collects natural gas from separator facilities located at or near the wellhead and delivers the natural gas to delivery points within the Mustang IDP. The natural gas is then processed by third parties.
As part of the Drop-Down and Simplification Transaction, we acquired gas infrastructure in the East Pony IDP which consists of an approximately 234-mile natural gas pipeline system. This natural gas gathering system collects natural gas from the wellhead and delivers it to our Lilli and Keota gas processing plants or other third-party processing facilities.
Our natural gas infrastructure assets in the Delaware Basin consist of five CGFs as well as an approximately 104-mile natural gas pipeline system servicing production from the Delaware Basin. This natural gas gathering system 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.
As part of the Drop-Down and Simplification Transaction, we acquired an approximately 112-mile natural gas pipeline system servicing production from the acreage in the Delaware Basin. This natural gas gathering system collects natural gas from the wellhead and terminates at various third-party pipeline connection points.
The table below sets forth our natural gas gathering throughput for the dates indicated.
 
Average Daily Throughput (MMBtu/d)
 
Year Ended December 31,
 
2019
 
2018
 
2017
DJ Basin
476,605

 
308,929

 
228,768

Delaware Basin
155,155

 
78,875

 
16,172

Natural Gas Processing
As part of the Drop-Down and Simplification Transaction, we acquired natural gas processing infrastructure in the DJ Basin which includes the Lilli and Keota gas processing plants connected to our gas gathering pipelines. The Lilli natural gas processing plant has an 18 MMcf/d capacity with a cryo unit and gas fired compression. The Keota natural gas processing plant has a 30 MMcf/d capacity, expandable to 45 MMcf/d with a cryo unit, truck load-out for drip condensate and electricity driven compression. The processing plants compress the natural gas, remove contaminants and separate the natural gas into individual natural gas liquids (“NGL”) components. The natural gas and NGL components are then transferred to third-party pipelines.
The table below sets forth our natural gas processing throughput for the dates indicated.
 
Average Daily Throughput (MMBtu/d)
 
Year Ended December 31,
 
2019
 
2018
 
2017
DJ Basin
50,039

 
61,766

 
49,531


11

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, permanent pipelines, as well as pumps to transport produced water to disposal facilities. We operate an approximately 83-mile gathering pipeline system (which is a shared crude oil and produced water gathering pipeline) servicing the Wells Ranch IDP. 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.
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 third-party disposal facilities. We operate an approximately 34-mile gathering pipeline system servicing the Mustang IDP.
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 third-party disposal facilities. We operate an approximately 31-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 third-party disposal facilities. We operate an approximately 118-mile gathering pipeline system servicing the Delaware Basin. At our CGFs, the incoming produced water is skimmed and pumped downstream to disposal wells.
As part of the Drop-Down and Simplification Transaction, we acquired an approximately 120-mile produced water gathering system servicing production from acreage in the Delaware Basin. This system gathers produced water to transport to third-party disposal locations.
We enter into and manage contracts with third-party providers for certain produced water services that we do not perform ourselves.
The table below sets forth our produced water gathering throughput for the dates indicated.
 
Average Daily Throughput (Bbl/d)
 
Year Ended December 31,
 
2019
 
2018
 
2017
DJ Basin
39,629

 
29,903

 
16,435

Delaware Basin
148,886

 
91,312

 
20,930

Fresh Water Delivery
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 buried pipelines, nine miles of which service the East Pony IDP, 22 miles of which service the Wells Ranch IDP, 12.5 miles which service the Mustang IDP, and 26 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.
The table below sets forth our fresh water delivery services throughput for the dates indicated.
 
Average Daily Throughput (Bbl/d)
 
Year Ended December 31,
 
2019
 
2018
 
2017
DJ Basin
164,524

 
175,754

 
155,990


12

Investments in Midstream Entities
Our Investments in Midstream Entities reportable segment includes our investments in Advantage, Delaware Crossing, EPIC Y-Grade, EPIC Crude and White Cliffs.
Advantage
We own a 50% interest in Advantage. 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.
Delaware Crossing
Delaware Crossing is constructing a 95-mile pipeline system that will originate in Pecos County, Texas, and have 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 210,000 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 first quarter of 2020.
EPIC Crude
EPIC Crude is constructing an approximately 700-mile pipeline with a capacity of 600 MBbl/d from the Delaware Basin to the Gulf Coast. EPIC Crude’s petition for declaratory order seeking approval of its rates and terms and conditions of its tariff was approved by the Federal Energy Regulatory Commission (“FERC”) on April 12, 2019. Construction on the project is anticipated to be complete in the first quarter of 2020.
EPIC Y-Grade
EPIC Y-Grade is constructing 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. Interim crude services commenced during the third quarter of 2019.
White Cliffs
We own a 3.33% interest in White Cliffs (the “White Cliffs Interest”). The White Cliffs Pipeline consists of two 527-mile pipelines, one for crude oil transport and one that is currently being converted to NGL service, that extend from the DJ Basin to Cushing, Oklahoma, with a capacity of approximately 215,000 Bbl/d.
Corporate
Our Corporate segment includes all general Partnership activity and expenses not attributable to our operating subsidiaries. This includes primarily expenses related to debt, such as interest and other debt-related costs, legal and financial advisory expenses and general and administrative expenses, including the annual general and administrative fee we pay to Noble for certain administrative and operational support services provided to us.
Regulations
The midstream services we provide are subject to regulations that may affect certain aspects of our business and the market for our services.
Colorado Oil and Gas Regulation
For some time, initiatives have been underway in the State of Colorado to limit or ban crude oil and natural gas exploration, development or operations. During first quarter 2019, Senate Bill 19-181 (“SB 181”) was passed by the State Legislature. On April 16, 2019, the Governor signed the bill into law. The legislation makes sweeping changes in Colorado oil and gas law, including, among other matters, requiring the Colorado Oil and Gas Conservation Commission (“COGCC”) to prioritize public health and environmental concerns in its decisions, instructing the COGCC to adopt rules to minimize emissions of methane and other air contaminants, and delegating considerable new authority to local governments to regulate surface impacts. Some local communities have adopted additional restrictions for oil and gas activities, such as requiring greater setbacks, and other groups have sought a cessation of permit issuances entirely until the COGCC publishes new rules in keeping with SB 181. Additionally, certain groups have submitted new ballot proposals for the 2020 election year, including proposals for increased drilling setbacks and increased bonding requirements.
Nevertheless, at this time, we are not aware of any significant changes to Noble’s or other third-party customers’ development plans. However, if additional regulatory measures are adopted, Noble and other third-party customers in Colorado could experience delays and/or curtailment in the permitting or pursuit of their exploration, development, or production activities. Such compliance costs and delays, curtailments, limitations, or prohibitions in their development plans could result in

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decreased demand for our services, which could have a material adverse effect on our cash flows, results of operations, financial condition, and liquidity.
Safety and Maintenance Regulation
We are subject to regulation by the United States Department of Transportation (“DOT”) under multiple pipeline safety laws, including the Hazardous Liquids Pipeline Safety Act of 1979 (“HLPSA”), the Natural Gas Pipeline Safety Act of 1968 (“NGPSA”) and comparable state statutes. These regulations include potential fines and penalties for violations.
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. The Pipeline and Hazardous Materials Safety Administration (“PHMSA”) has undertaken rulemaking to address many areas of this legislation.
For example, in October 2019, PHMSA published three final rules that create or expand reporting, inspection, maintenance, and other pipeline safety obligations. We are in the process of assessing the impact of these rules on our future costs of operations and revenues from operations. PHMSA is working on two additional rules related to gas pipeline safety that are expected to modify pipeline repair criteria and extend regulatory safety requirements to certain gathering lines in rural areas. These additional rulemakings are expected to be effective by mid-2020. The adoption of these or other regulations requiring more comprehensive or stringent safety standards could require us to install new or modified safety controls, pursue additional capital projects, or conduct maintenance programs on an accelerated basis, any or all of which tasks could result in our incurring increased operating costs that could have a material adverse effect on our results of operations or financial position.
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 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 (“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 (“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. 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 (“CAA”) to prevent the accidental release of extremely hazardous substances. We have an internal program of inspection designed to monitor and enforce compliance with safeguard and security requirements.
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 (“NGA”) exempts natural gas gathering facilities from the jurisdiction of the FERC under the NGA. We believe that our natural gas gathering facilities meet the traditional tests the FERC has used to establish a pipeline’s status as a gathering pipeline and therefore our natural gas gathering facilities should not be subject to FERC jurisdiction. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services has been the subject of 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 some or all of our gathering facilities or the services provided by us are not exempt from FERC regulation, the rates for, and

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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 (“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 $1,291,894 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 penalties.
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 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 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.
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 (“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 may also 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 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, we operate multiple pipeline gathering systems that transport crude oil in interstate commerce. 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 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

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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, we own interests in other crude oil gathering pipelines that do not provide interstate services and are not subject to regulation by the FERC. These pipelines regulated by the Railroad Commission of Texas (the “RRC”), and 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.
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. We continue to monitor proposed and new regulations and legislation in all our operating jurisdictions to assess the potential impact on our company.
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.
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.
In the United States, no comprehensive climate change legislation has been implemented at the federal level. However, following the U.S. Supreme Court finding that greenhouse gas (“GHG”) emissions constitute a pollutant under the CAA, the EPA has adopted regulations that, among other things, establish construction and operating permit reviews for GHG emissions from certain large stationary sources, require the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the United States, implement New Source Performance Standards directing the reduction of

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methane from certain new, modified, or reconstructed facilities in the oil and natural gas sector, and together with the DOT, implement GHG emissions limits on vehicles manufactured for operation in the United States. Following the change in presidential administrations, there have been attempts to modify certain of these regulations, and litigation is ongoing.
Additionally, various states and groups of states have adopted or are considering adopting legislation, regulations or other regulatory initiatives that are focused on such areas as GHG cap and trade programs, carbon taxes, reporting and tracking programs, and restriction of GHG emissions. At the international level, there is a non-binding agreement, the United Nations-sponsored “Paris Agreement,” for nations to limit their GHG emissions through individually-determined reduction goals every five years after 2020, although the United States has announced its withdrawal from such agreement, effective November 4, 2020. The adoption and implementation of new or more stringent legislation or regulations could result in increased costs of compliance or costs of consuming, and thereby reduce demand for, oil and natural gas, which could reduce demand for our services and products.
Concern over the threat of climate change may also result in political action deleterious to our interests. For example, various pledges to curtail oil and gas operations have been made by candidates running for the Democratic nomination for President of the United States in 2020. Separately, increased attention to climate change risks has increased the possibility of claims brought by public and private entities against oil and gas companies in connection with their GHG emissions. While courts have generally declined to assign direct liability for climate change to large sources of GHG emissions, new claims for damages and increased government scrutiny, especially from state and local governments, will likely continue. Moreover, to the extent societal pressures or political or other factors are involved, it is possible that such liability could be imposed without regard to the company’s causation of or contribution to the asserted damage, or to other mitigating factors.
There are also increasing financial risks for fossil fuel producers as shareholders currently invested in fossil-fuel energy companies concerned about the potential effects of climate change may elect in the future to shift some or all of their investments into non-energy related sectors. Institutional lenders who provide financing to fossil-fuel energy companies also have become more attentive to sustainable lending practices and some of them may elect not to provide funding for fossil fuel energy companies. Additionally, the lending practices of institutional lenders have been the subject of intensive lobbying efforts in recent years, oftentimes public in nature, by environmental activists, proponents of the international Paris Agreement, and foreign citizenry concerned about climate change not to provide funding for fossil fuel producers. Limitation of investments in and financings for fossil fuel energy companies could result in the restriction, delay or cancellation of drilling programs or development or production activities. One or more of these developments could have a material adverse effect on our business, financial condition and results of operation.
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 (“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 (“RCRA”), and comparable state statutes. While RCRA regulates both solid and hazardous wastes, it imposes strict requirements on the generation, storage, treatment, transportation and disposal of hazardous wastes. Certain petroleum production wastes are excluded from RCRA’s hazardous waste regulations. However, it is possible that these wastes, which could include wastes currently generated during our operations, will in the future be designated as hazardous wastes and therefore be subject to more rigorous and costly disposal requirements. Any such changes in the laws and regulations could have a material adverse effect on our maintenance capital expenditures and operating expenses.
We currently own or lease properties where petroleum hydrocarbons are being or have been handled for many years. Although we have utilized operating and disposal practices that were standard in the industry at the time, petroleum

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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 (“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 (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.” Following the change in U.S. Presidential Administrations, there have been several attempts to modify or eliminate this rule. Most recently, in September 2019, the EPA and Corps rescinded the 2015 Clean Water Rule. Legal challenges have occurred for both the 2015 rule and the 2019 rescission. 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 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.
The Oil Pollution Act of 1990 (“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 (“NOV/CDO”), advising us of alleged violations of the Colorado Water Quality Control Act (“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 applicable permit (“Permit”).  The NOV/CDO further ordered us to cease and desist from all violations of the CWQCA, the regulations and the Permit and to undertake certain corrective actions. In October 2019, we resolved by Compliance Order on Consent (“COC”) with the Colorado Department of Public Health & Environment allegations of noncompliance with the CWQCA relating to the Permit. The COC required us to pay a penalty of $26,000 and to contribute $53,000 toward a State-managed supplemental environmental project. The resolution of this action did 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

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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. 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.
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 its 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. 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 initial public offering (“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. With respect to our completed midstream systems, we do not expect seasonal conditions to have a material impact on our throughput volumes. Severe or prolonged winters may, however, impact our ability to complete additional well connections or construction projects, which may impact the rate of our growth. In addition, severe 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, 2019, revenues from Noble and its affiliates comprised 81% and 59% of our midstream services revenues and total revenues, respectively. There were no individually significant revenues from a third-party in 2019.
For the year ended December 31, 2018, revenues from Noble and its affiliates comprised 81% and 61% of our midstream services revenues and total revenues, respectively. Revenues from a single third-party customer comprised 66% and 17% of our crude oil sales revenues and total revenues, respectively.
For the year ended December 31, 2017, revenues from Noble and its affiliates comprised 94% of both of our midstream services revenues and total revenues. There were no individually significant revenues from a third-party in 2017.

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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.
However, in the Delaware Basin, Noble is currently using third-party service providers for certain midstream services, and Noble will continue using the third-party service providers until the expiration or termination of certain pre-existing dedications to those third-party service providers. After the expiration of such dedications, we will not compete for Noble’s business in the Delaware Basin. 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, Noble Midstream GP LLC (“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 and omnibus agreement that we entered into with Noble. As of December 31, 2019, Noble employed approximately 240 people who provide direct support to our operations pursuant to the operational services and secondment agreement and omnibus 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 Nasdaq Global Select Market (“Nasdaq”) 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 Nasdaq, 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, 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:
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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;
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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;
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the availability of capital on an economic basis to fund Noble’s exploration and development activities;
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drilling and operating risks, including potential environmental liabilities, associated with Noble’s operations on our dedicated acreage;
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downstream processing and transportation capacity constraints and interruptions, including the failure of Noble to have sufficient contracted processing or transportation capacity; and
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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:
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Noble’s financial condition, credit ratings, leverage, market reputation, liquidity and cash flows;
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Noble’s ability to maintain or replace its reserves;
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adverse effects of governmental and environmental regulation on Noble’s upstream operations; and
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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 conducting development drilling activities in both the DJ and Delaware Basins. A decrease in development drilling and completion activities 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. Our long-term commercial agreements with Noble carry initial terms for 15 years, and there is no guarantee that we will be able to renew or replace these agreements on equal or better terms, or at all, upon their expiration. Our ability to renew or replace our 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-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.

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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.
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:
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the volumes of natural gas we gather or process, 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;
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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;
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our customers’ ability to fund their drilling and development plans on our dedicated acreage;
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downstream processing and transportation capacity constraints and interruptions, including the failure of our customers to have sufficient contracted processing or transportation capacity;
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the levels of our operating expenses, maintenance expenses and general and administrative expenses;
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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;
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the rates we charge third parties for our midstream services;
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prevailing economic conditions; and
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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:
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the level and timing of our capital expenditures;
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our debt service requirements and other liabilities;
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our ability to borrow under our debt agreements to fund our capital expenditures and operating expenditures and to pay distributions;
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fluctuations in our working capital needs;
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restrictions on distributions contained in any of our debt agreements;
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the cost of acquisitions, if any;
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the fees and expenses of our General Partner and its affiliates (including Noble) that we are required to reimburse;
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the amount of cash reserves established by our General Partner; and
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other business risks affecting our cash levels.
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:

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the availability and cost of capital;
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prevailing and projected crude oil, natural gas and NGL prices;
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demand for crude oil, natural gas and NGLs;
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levels of reserves;
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geologic considerations;
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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;
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increased levels of taxation related to the exploration and production of crude oil, natural gas and NGLs in our areas of operation;
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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
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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.
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.
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 where the acreage is not dedicated to us. Our customers’ decisions to develop acreage that is not dedicated to us 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.
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

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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 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. Noble is under no obligation to offer to sell us additional assets, we are under no obligation to buy any additional assets from Noble and we do not know when or if Noble will decide to make any offers to sell assets to us.
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:
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mistaken assumptions about volumes or the timing of those volumes, revenues or costs, including synergies;
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an inability to successfully integrate the acquired assets or businesses;
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the assumption of unknown liabilities;
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exposure to potential lawsuits;
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limitations on rights to indemnity from the seller;
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the diversion of management’s and employees’ attention from other business concerns;
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unforeseen difficulties operating in new geographic areas; and
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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 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

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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 growth capital expenditures, 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.
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.
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.

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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.
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 listed above. 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 systems no longer qualify for a waiver. FERC could, either at the request of other entities or on its own initiative, assert that some or all of our pipelines no longer qualify 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 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 our FERC jurisdictional pipelines that have tariffs on file, including White Cliffs Pipeline, EPIC Y-Grade, EPIC Crude and the gathering systems listed above 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. Pipelines may utilize the FERC oil pipeline indexing methodology which, as currently in effect, allows common carriers to change their rates within

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prescribed ceiling levels that are tied to changes in the Producer Price Index. The FERC’s establishment of a just and reasonable rate, including the determination of the oil pipeline index, is based on many components, and tax-related changes will affect two such components, the allowance for income taxes and the amount for accumulated deferred income taxes (“ADIT”). The FERC’s oil pipeline index is reviewed every five years. On March 15, 2018, as clarified on July 18, 2018, the FERC issued a Revised Policy Statement on Treatment of Income Taxes (“Revised Policy Statement”) stating, among other things, that it will no longer permit master limited partnerships to recover an income tax allowance in their cost-of-service-rates. To the extent a regulated entity is permitted to include an income tax allowance in its cost-of-service, the 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. Further, should such regulated entity not include an income tax allowance in their cost-of-service rates, such entity may also elect to exclude the ADIT balance from the rate calculation. The impacts of the Revised Policy Statement and the Tax Cuts and Jobs Act of 2017 on the costs of FERC-regulated oil and NGL pipelines will be reflected in the FERC’s next five-year review of the oil pipeline index, which will be initiated in 2020 to generate the index level to be effective July 1, 2021. Accordingly, if any of our waivers are revoked, the FERC’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 in the future, including indexed 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.
Changes to existing pipeline safety regulations may result in increased operating and compliance costs. For example, in October 2019, PHMSA published three final rules that create or expand reporting , inspection, maintenance, and other pipeline safety obligations. We are in the process of assessing the impact of these rules on our future costs of operations and revenue from operations.
PHMSA is working on two additional rules related to gas pipeline safety that are expected to modify pipeline repair criteria and extend regulatory safety requirements to certain gathering lines in rural areas. These additional rulemakings are expected to be effective by mid-2020. The adoption of these or other regulations requiring more comprehensive or stringent safety standards could require us to install new or modified safety controls, pursue additional capital projects, or conduct maintenance programs on an accelerated basis, any or all of which tasks could result in our incurring increased operating costs that could have a material adverse effect on our results of operations or financial position.
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 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.

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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:
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the level of existing and new competition to provide services to our markets;
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the macroeconomic factors affecting our current and potential customers;
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the balance of supply and demand, on a short-term, seasonal and long-term basis, in our markets;
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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.

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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.
During first quarter 2019, SB 181 was passed by the State Legislature. On April 16, 2019, the Governor signed the bill into law. The legislation makes sweeping changes in Colorado oil and gas law, including, among other matters, requiring the COGCC to prioritize public health and environmental concerns in its decisions, instructing the COGCC to adopt rules to minimize emissions of methane and other air contaminants, and delegating considerable new authority to local governments to regulate surface impacts. Some local communities have adopted additional restrictions for oil and gas activities, such as requiring greater setbacks, and other groups have sought a cessation of permit issuances entirely until the COGCC publishes new rules in keeping with SB 181. Additionally, activist groups have submitted new ballot proposals for the 2020 election year, including proposals for increased drilling setbacks and increased bonding requirements.
Nevertheless, at this time, we are not aware of any significant changes to Noble’s or other third-party customers’ development plans. However, if additional regulatory measures are adopted, Noble and other third-party customers in Colorado could experience delays and/or curtailment in the permitting or pursuit of their exploration, development, or production activities.
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 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

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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 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. Following the change in U.S. Presidential Administrations, there have been several attempts to modify or eliminate this rule, also known as the Clean Water Rule. Most recently, in September 2019, the EPA and Corps rescinded the 2015 Clean Water Rule. Legal challenges have occurred for both the 2015 rule and the 2019 rescission. 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.
Our and our customers’ operations are subject to a series of risks arising out of the threat of climate change that could result in increased operating costs, limit the areas in which oil and natural gas production may occur, and reduce demand for the products and services we provide.
The threat of climate change continues to attract considerable attention in the United States and in foreign countries. Numerous proposals have been made and could continue to be made at the international, national, regional and state levels of government to monitor and limit existing emissions of GHGs as well as to restrict or eliminate such future emissions. As a result, our operations as well as the operations of our oil and natural gas exploration and production customers are subject to a series of regulatory, political, litigation, and financial risks associated with the production and processing of fossil fuels and emission of GHGs.
In the United States, no comprehensive climate change legislation has been implemented at the federal level. However, following the U.S. Supreme Court finding that GHG emissions constitute a pollutant under the CAA, the EPA has adopted regulations that, among other things, establish construction and operating permit reviews for GHG emissions from certain large stationary sources, require the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the United States, implement New Source Performance Standards directing the reduction of methane from certain new, modified, or reconstructed facilities in the oil and natural gas sector, and together with the DOT, implement GHG emissions limits on vehicles manufactured for operation in the United States. Following the change in presidential administrations, there have been attempts to modify certain of these regulations, and litigation is ongoing.
Additionally, various states and groups of states have adopted or are considering adopting legislation, regulations or other regulatory initiatives that are focused on such areas as GHG cap and trade programs, carbon taxes, reporting and tracking programs, and restriction of GHG emissions. At the international level, there is a non-binding agreement, the United Nations-sponsored “Paris Agreement,” for nations to limit their GHG emissions through individually-determined reduction goals every five years after 2020, although the United States has announced its withdrawal from such agreement, effective November 4, 2020. The adoption and implementation of new or more stringent legislation or regulations could result in increased costs of compliance or costs of consuming, and thereby reduce demand for, oil and natural gas, which could reduce demand for our services and products.
Concern over the threat of climate change may also result in political action deleterious to our interests. For example, various pledges to curtail oil and gas operations have been made by candidates running for the Democratic nomination for President of

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the United States in 2020. Separately, increased attention to climate change risks has increased the possibility of claims brought by public and private entities against oil and gas companies in connection with their GHG emissions. While courts have generally declined to assign direct liability for climate change to large sources of GHG emissions, new claims for damages and increased government scrutiny, especially from state and local governments, will likely continue. Moreover, to the extent societal pressures or political or other factors are involved, it is possible that such liability could be imposed without regard to the company’s causation of or contribution to the asserted damage, or to other mitigating factors.
There are also increasing financial risks for fossil fuel producers as shareholders currently invested in fossil-fuel energy companies concerned about the potential effects of climate change may elect in the future to shift some or all of their investments into non-energy related sectors. Institutional lenders who provide financing to fossil-fuel energy companies also have become more attentive to sustainable lending practices and some of them may elect not to provide funding for fossil fuel energy companies. Additionally, the lending practices of institutional lenders have been the subject of intensive lobbying efforts in recent years, oftentimes public in nature, by environmental activists, proponents of the international Paris Agreement, and foreign citizenry concerned about climate change not to provide funding for fossil fuel producers. Limitation of investments in and financings for fossil fuel energy companies could result in the restriction, delay or cancellation of drilling programs or development or production activities. One or more of these developments could have a material adverse effect on our business, financial condition and results of operation.
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 under such laws, may affect our and Noble’s operations by imposing additional costs, approvals and accompanying delays. For example, the Bureau of Land Management has deferred the sale of leases on certain lands due to concerns about protections for the greater sage grouse, a species that, while not currently listed, has been the subject of long-term and recently renewed calls for protection under the ESA.
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.
Section 1(b) of the Natural Gas Act of 1938 (“NGA”) exempts natural gas gathering facilities from regulation as a natural gas company by FERC under the NGA. 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 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.

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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:
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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;
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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;
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unexpected business interruptions;
•
curtailments of operations due to severe seasonal weather;
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riots, strikes, lockouts or other industrial disturbances;
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fires, ruptures and explosions; and
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other hazards that could also result in personal injury and loss of life, pollution and suspension of operations.
Any of these risks could adversely affect our ability to conduct operations or result in substantial loss to us as a result of claims for:
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injury or loss of life;
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damage to and destruction of property, natural resources and equipment;
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pollution and other environmental damage;
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regulatory investigations and penalties;
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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.
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

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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. 
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 some of the land on which our pipelines and facilities are located, which could result in disruptions to our operations.
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 Brent J. Smolik, our Chief Executive Officer, Thomas W. Christensen, our Chief Financial Officer, Robin H. Fielder, our Chief Operating Officer, Phillip S. Welborn, our Chief Accounting Officer, and Aaron G. Carlson, 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:
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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;
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we may be more vulnerable to competitive pressures or a downturn in our business or the economy generally; and
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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

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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, 2019, $595 million and $900 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 $9.5 million increase in interest expense for the year ended December 31, 2019. 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:
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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;
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a cyber attack on downstream pipelines could prevent us from delivering product at the tailgate of our facilities, resulting in a loss of revenues;
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a cyber attack on a communications network or power grid could cause operational disruption resulting in loss of revenues;
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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

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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 62.6% 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:
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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;
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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;
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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;
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except in limited circumstances, our General Partner has the power and authority to conduct our business without unitholder approval;
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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;
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our General Partner will determine which costs incurred by it are reimbursable by us;
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our General Partner may cause us to borrow funds in order to permit the payment of cash distributions;
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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;
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our General Partner intends to limit its liability regarding our contractual and other obligations;
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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;
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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; and
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our General Partner decides whether to retain separate counsel, accountants or others to perform services for us.
Neither our partnership agreement nor our omnibus agreement will prohibit Noble or any other affiliates of our General Partner from owning assets or engaging in businesses that compete directly or indirectly with us. Under the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, will not apply to our General Partner or any of its affiliates, including Noble and executive officers and directors of our General Partner. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will not have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. Consequently, Noble and other affiliates of our General Partner may acquire, construct or

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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.
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:
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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;
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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;
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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

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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 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 62.6% of our total outstanding Common Units. 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

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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.
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:
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management of our business may no longer reside solely with our current General Partner; and
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affiliates of the newly admitted General Partner may compete with us, and neither that General Partner nor such affiliates will have any obligation to present business opportunities to us except with respect to rights of first refusal contained in our omnibus agreement.
Noble may sell units in the public or private markets, and such sales could have an adverse impact on the trading price of the Common Units.
Noble currently holds 56,447,616 Common Units. 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 permits the General Partner to reduce available cash by establishing cash reserves for the proper conduct of our business, (including reserves for future capital expenditures and for our anticipated future credit needs) 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.


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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 62.6% 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).
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.
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 would limit our unitholders’ ability to choose the judicial forum for disputes with us or our general partner’s directors, officers or other employees. Our partnership agreement also provides that any unitholder bringing an unsuccessful action will be obligated to reimburse us for any costs we have incurred in connection with such unsuccessful action.
Our partnership agreement 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.
The exclusive forum provision would not apply to suits brought to enforce any liability or duty created by the Securities Act or the Exchange Act or any other claim for which the federal courts have exclusive jurisdiction. To the extent that any such claims may be based upon federal law claims, Section 27 of the Exchange Act creates exclusive federal jurisdiction over all suits brought to enforce any duty or liability created by the Exchange Act or the rules and regulations thereunder. Furthermore,

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Section 22 of the Securities Act creates concurrent jurisdiction for federal and state courts over all suits brought to enforce any duty or liability created by the Securities Act or the rules and regulations thereunder.
The enforceability of similar choice of forum provisions in other companies’ certificates of incorporation or similar governing documents has been challenged in legal proceedings, and it is possible that a court could find the choice of forum provisions contained in our partnership agreement to be inapplicable or unenforceable, including with respect to claims arising under the U.S. federal securities laws. This exclusive forum provision may limit the ability of a limited partner to commence litigation in a forum that the limited partner prefers, or may require a limited partner to incur additional costs in order to commence litigation in Delaware, each of which may discourage such lawsuits against us or our general partner’s directors or officers. Alternatively, if a court were to find this exclusive forum provision inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings described above, we may incur additional costs associated with resolving such matters in other jurisdictions, which could negatively affect our business, results of operations and financial condition.
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. However, such waiver of the right to trial by jury does not impact the ability of a limited partner to make a claim under either federal or state law. 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.
Our partnership agreement provides that unitholders irrevocably waive the right to trial by jury in any claim, suit, action or proceeding under either state or federal laws, including any claim under U.S. federal securities laws, which could result in less favorable outcomes to unitholders in any such action.
Our partnership agreement provides that unitholders irrevocably waive the right to trial by jury for any claims, suits, actions or proceedings under either state or federal laws, including any claim under U.S. federal securities laws. Regardless, such waiver of the right to trial by jury does not impact the ability of a unitholder to make a claim under either federal or state law. The waiver of the right to a jury trial is not intended to be deemed a waiver by a unitholder with respect to the Partnership’s compliance with U.S. federal securities laws and the rules and regulations promulgated thereunder. If the Partnership or one of its unitholders opposed a jury trial demand based on the waiver, the applicable court would determine whether the waiver was enforceable based on the facts and circumstances of that case in accordance with applicable state and federal laws. To our knowledge, the enforceability of a contractual pre-dispute jury trial waiver in connection with claims arising under the U.S. federal securities laws has not been finally adjudicated by the United States Supreme Court. However, we believe that a contractual pre-dispute jury trial waiver provision is generally enforceable, including under the laws of the State of Delaware, which govern our partnership agreement.
If a unitholder brings a claim in connection with matters arising under our partnership agreement, including claims under U.S. federal securities laws, such unitholder may not be entitled to a jury trial with respect to such claims, which may have the effect of limiting and discouraging lawsuits. If a lawsuit is brought by a unitholder under our partnership agreement, it may be heard only by a judge or justice of the applicable trial court, which would be conducted according to different civil procedures and may result in a different outcome than a trial by jury, including results that could be less favorable to the unitholder(s) bringing such lawsuit.
Nasdaq 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 Nasdaq. Because we are a publicly traded limited partnership, Nasdaq 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 Nasdaq’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 Nasdaq’s corporate governance requirements.

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If we are deemed an “investment company” under the Investment Company Act of 1940, it would adversely affect the price of our Common Units and could have a material adverse effect on our business.
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 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.
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 certain 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. Any modification to the U.S. federal income tax laws and interpretations thereof may or may not

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be retroactively applied and could make it more difficult or impossible for us to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes. We are unable to predict whether any changes or other proposals will ultimately be enacted. Any future legislative changes 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.
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, as a result of any such adjustment, 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. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if a unitholder sells its units, a unitholder may incur a tax liability in excess of the amount of cash received from the sale.
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.

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Unitholders may be subject to limitations on their ability to deduct interest expense we incur.
In general, we are entitled to a deduction for interest paid or accrued on indebtedness properly allocable to our trade or
business during our taxable year. However, under the Tax Cuts and Jobs Act, for taxable years beginning after December 31, 2017, our deduction for “business interest” is limited to the sum of our business interest income and 30% of our “adjusted taxable income.” For the purposes of this limitation, our adjusted taxable income is computed without regard to any business interest expense or business interest income, and in the case of taxable years beginning before January 1, 2022, any deduction allowable for depreciation, amortization, or depletion to the extent such depreciation, amortization, or depletion is not capitalized into cost of goods sold with respect to inventory. If our “business interest” is subject to limitation under these rules, our unitholders will be limited in their ability to deduct their share of any interest expense that has been allocated to them. As a result, unitholders may be subject to limitation on their ability to deduct interest expense incurred by us.
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.
Moreover, the transferee of an interest in a partnership that is engaged in a U.S. trade or business is generally required to withhold 10% of the amount realized by the transferor unless the transferor certifies that it is not a foreign person, and we are required to deduct and withhold from the transferee amounts that should have been withheld by the transferees but were not withheld. Because the “amount realized” includes a partner’s share of the partnership’s liabilities, 10% of the amount realized could exceed the total cash purchase price for the units. However, pending the issuance of final regulations, the IRS has suspended the application of this withholding rule to transfers of publicly traded interests in publicly traded partnerships. If recently promulgated regulations are finalized as proposed, such regulations would provide, with respect to transfers of publicly traded interests in publicly traded partnerships effected through a broker, that the obligation to withhold is imposed on the transferor’s broker and that a partner’s “amount realized” does not include a partner’s share of a publicly traded partnership’s liabilities for purposes of determining the amount subject to withholding. However, it is not clear when such regulations will be finalized and if they will be finalized in their current form.
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

43

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 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.
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.

44

PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
On December 16, 2019, acting pursuant to authorization from the Board of our General Partner, we provided notice to the New York Stock Exchange (“NYSE”) of our intent to voluntarily withdraw the principal listing of our Common Units representing limited partner interests, from the NYSE and transfer the listing to Nasdaq. Our Common Units were voluntarily delisted effective as of the close of trading on December 27, 2019, and trading commenced on Nasdaq at market open on December 30, 2019. Our Common Units continue to trade under the symbol “NBLX”.
As of December 31, 2019, our units were held by 19 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, 2019, Noble owned 56,447,616 of our Common Units, which represent a 62.6% limited partner interest in us.
Securities Authorized for Issuance Under Equity Compensation Plans 
In 2016, 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, 2019.
The following table summarizes information regarding the number of Common Units that are available for issuance under our LTIP as of December 31, 2019.
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
—

—

1,630,638

Equity Compensation Plans Not Approved by Security Holders
—

—

—

Total
—

—

1,630,638

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 23, 2020, the Board of our General Partner declared a quarterly cash distribution of $0.6878 per limited partner unit. The distribution will be paid on February 14, 2020, to unitholders of record on February 4, 2020.
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 $0.375);
•
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.

45

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.
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.
Simplification of Incentive Distribution Rights
On November 14, 2019, all of the IDRs were converted into Common Units as part of the Drop-Down and Simplification Transaction.
Conversion of Subordinated Units
On April 25, 2019, the Board of our General Partner declared a quarterly cash distribution of $0.6132 per unit for the quarter ended March 31, 2019. The distribution was paid on May 13, 2019 to unitholders of record as of the close of business on May 6, 2019. Upon payment of such distribution, the requirements for the conversion of all Subordinated Units were satisfied under our partnership agreement. As a result, on May 14, 2019, all 15,902,584 Subordinated Units, which were owned entirely by Noble, converted into Common Units on a one-for-one basis and thereafter have or will continue to participate on terms equal with all other Common Units in distributions from available cash.


46

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. Our consolidated financial statements have been retrospectively recast for all periods presented to include the historical results of NBL Holdings, as the acquisition of NBL Holdings by the Partnership in the Drop-Down and Simplification Transaction represented a transaction between entities under common control. The selected financial data covering the periods prior to the aforementioned transactions may not necessarily be indicative of the actual results of operations had these entities been operated together during those periods.
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,
(in thousands, except as noted)
2019
 
2018
 
2017
 
2016
 
2015
Statements of Operations
 
 
 
 
 
 
 
 
 
Total Revenues
$
703,801

 
$
558,735

 
$
289,622

 
$
193,453

 
$
117,878

Net Income
245,467

 
216,719

 
160,767

 
96,290

 
(88,344
)
Net Income Attributable to Noble Midstream Partners LP
159,996

 
162,734

 
140,572

 
28,458

 
N/A

 
 
 
 
 
 
 
 
 
 
Net Income Attributable to Limited Partners Per Limited Partner Unit — Basic
 
 
 
 
 
 
 
 
 
Common Units
$
3.09

 
$
3.96

 
$
4.10

 
$
0.89

 
N/A

Subordinated Units
3.86

 
3.96

 
4.10

 
0.89

 
N/A

Cash Distributions Declared per Limited Partner Unit
2.6144

 
2.1913

 
1.8113

 
0.4333

 
N/A

 
 
 
 
 
 
 
 
 
 
Balance Sheet
 
 
 
 
 
 
 
 
 
Cash and Cash Equivalents
$
12,676

 
$
14,761

 
$
20,090

 
$
57,443

 
$
30,299

Total Property, Plant and Equipment, Net
1,762,957

 
1,570,923

 
821,962

 
380,310

 
352,764

Investments
660,778

 
82,317

 
80,461

 
11,151

 
12,279

Intangible Assets, Net
277,900

 
310,202

 
—

 
—

 
—

Goodwill
109,734

 
109,734

 
—

 
—

 
—

Total Assets
2,926,082

 
2,192,178

 
1,038,465

 
537,430

 
481,853

Long-Term Debt
1,495,679

 
559,021

 
85,000

 
—

 
—

Total Liabilities
1,665,221

 
705,623

 
251,806

 
50,368

 
61,674

Mezzanine Equity
106,005

 
—

 
—

 
—

 
—

Total Equity
1,154,856

 
1,486,555

 
786,659

 
487,062

 
420,179

 
 
 
 
 
 
 
 
 
 
Throughput and Crude Oil Sales Volumes
 
 
 
 
 
 
 
 
 
Crude Oil Sales Volumes (Bbl/d)
9,354

 
6,129

 
—

 
—

 
—

Crude Oil Gathering Volumes (Bbl/d)
231,963

 
177,127

 
69,249

 
45,236

 
33,977

Natural Gas Gathering Volumes (MMBtu/d)
631,760

 
387,804

 
244,940

 
180,262

 
100,298

Total Barrels of Oil Equivalent (Boe/d)
322,312

 
232,974

 
100,652

 
68,347

 
46,836

Natural Gas Processing Volumes (MMBtu/d)
50,039

 
61,766

 
49,531

 
42,269

 
11,735

Produced Water Gathering Volumes (Bbl/d)
188,515

 
121,215

 
37,365

 
10,592

 
5,198

Fresh Water Services Volumes (Bbl/d)
164,524

 
175,754

 
155,990

 
94,227

 
51,980


47

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:
•
•
•
•
•
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. Our business activities are conducted through four reportable segments: Gathering Systems (primarily includes crude oil gathering, natural gas gathering and processing, produced water gathering and crude oil sales), Fresh Water Delivery, Investments in Midstream Entities and Corporate. 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.
2019 Initiatives and Results
During 2019, our activities were focused on positioning the Partnership for sustainable, long-term cash flows through the following initiatives:
Developing Strategic Relationships Our strategic relationships, including with Saddlehorn, in the DJ Basin, and with EPIC Y-Grade, EPIC Crude Holdings, and Delaware Crossing in the Delaware Basin, resulted in expansion of our long-haul business downstream of our gathering systems and an increase in dedications.
Improving Cost Structure Despite record throughput, capital expenditures trended below our expectations for the year, due to consistent cost focus, utilization of existing infrastructure, and to a lesser extent, the timing of customer activity. Cost savings initiatives included project scope and design optimization and more efficient construction processes as well as an enhanced contracting strategy.
Expanding our Third-party Business We significantly increased midstream services revenues, particularly in the DJ Basin, through additional well connections to existing customers and adding new customers to our systems.
Managing Liquidity We utilized a new term loan facility, preferred equity commitment and common unit offerings to provide liquidity while executing our growth opportunities, including the entry into multiple new partnerships.
Returning Value to Unit Holders While executing our growth opportunities, we were able to provide consistent quarterly distribution increases to our unitholders.
Increasing Alignment and Operational Synergies with Noble Through the Drop-Down and Simplification Transaction, we simplified our relationship with Noble through the elimination of IDRs and the acquisition of the remaining ownership interest in our DevCos as well as gained additional midstream assets.
Specifically, we accomplished the following significant transactional and financial results for the year ended December 31, 2019.

48

Significant Transactional Highlights Include:
•
completed the Drop-Down and Simplification Transaction;
•
completed the formation of Delaware Crossing;
•
closed options to acquire interests in EPIC Y-Grade and EPIC Crude;
•
secured equity commitment and issued preferred equity to GIP CAPS Dos Rios Holding Partnership, L.P. (“GIP”);
•
entered into an additional term loan credit facility that permitted aggregate borrowing up to $400 million; and
•
extended the borrowing capacity of our revolving credit facility to $1.15 billion.
Significant Financial Highlights Include:
•
net income of $245.5 million, an increase of 13% as compared with 2018;
•
net cash provided by operating activities of $385.1 million, an increase of 41% as compared with 2018;
•
Adjusted EBITDA (non-GAAP financial measure) of $385.9 million, an increase of 18% as compared with 2018;
•
Adjusted EBITDA (non-GAAP financial measure) attributable to the partnership of $254.6 million, an increase of 14% as compared with 2018; and
•
distributable cash flow (non-GAAP financial measure) of $213.4 million, an increase of 17% as compared with 2018.
OPERATING OUTLOOK
2019 Development Project Updates
DJ Basin
In the Greeley Crescent IDP area, we commenced construction on the trunkline extensions supporting future produced water gathering and fresh water delivery services. During the year, we connected 72 wells in Greeley Crescent IDP for two stream gathering services and delivered fresh water to 70 wells.
In the Black Diamond dedication area, we progressed the Milton Phase I Terminal expansion project that increased outlet pumping capacity and we installed new oil gathering infrastructure for upcoming well connections from third-party producers. During the year, we connected 260 third-party wells to the Black Diamond gathering system. Black Diamond added a long-term oil gathering dedication from a third-party customer. The dedication increased Black Diamond dedicated acres by approximately 85,000 acres, or 54%.
In the Mustang IDP area, we extended infrastructure for crude oil, natural gas and produced water gathering systems to facilitate further development and support future well connections. We also completed additional natural gas offload capacity to facilitate future growth from the area. During the year, we connected 56 wells to the Mustang gathering system.
In the Wells Ranch IDP area, we commenced construction on extensions of gathering infrastructure to support future well connections. During the year, we connected and delivered fresh water to 42 wells.
In the East Pony IDP area, we connected and delivered fresh water to 22 wells during the year.
Delaware Basin
In the Permian, we connected 13 sponsored wells and six third-party wells to our gathering systems. We are now connected to 151 sponsor and 15 third-party wells. We also plan to add further compression capacity to our CGFs during 2020.
Saddlehorn Transportation Commitment and Investment Option
During 2019, Black Diamond entered into a strategic relationship with Saddlehorn. Saddlehorn is jointly owned by affiliates of Magellan, Plains and Western Midstream. The Saddlehorn pipeline is currently capable of transporting approximately 190 MBbl/d of crude oil and condensate from the DJ Basin and the Powder River Basin to storage facilities in Cushing, Oklahoma owned by Magellan and Plains. With the recent successful open season, the Saddlehorn pipeline will be expanded by 100 MBbl/d, to a new total capacity of 290 MBbl/d. The higher capacity is expected to be available in late 2020 following the addition of incremental pumping and storage capabilities.
As part of the strategic relationship, Black Diamond and Noble entered into long-term firm transportation commitments with Saddlehorn. See Item 8. Financial Statements and Supplementary Data – Note 15. Commitments and Contingencies. Black Diamond received an option to acquire an ownership interest of up to 20% in Saddlehorn. Black Diamond’s investment option was scheduled to expire in April 2020. In February 2020, Black Diamond exercised its option, effective February 1, 2020, and acquired the 20% ownership interest for $155 million, or $84 million net to the Partnership. After Black Diamond’s purchase, with Magellan and Plains each selling a 10% interest, Magellan and Plains each own a 30% membership interest and Black

49

Diamond and Western Midstream each own a 20% membership interest in Saddlehorn. Magellan continues to serve as operator of the Saddlehorn pipeline. The Partnership funded its share of the transaction price with available cash and a draw under its revolving credit facility.
2020 Capital Program
Organic Capital Program
Our 2020 organic capital program will accommodate a net investment level of approximately $190 to $230 million. The Partnership has lowered previously-issued 2020 organic net capital expectations by 25% due to continued progress on sustainable costs savings, including a reduction in pipeline installation costs and improved planning and construction solutions for projects as well as better line of sight to customer activity. 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 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.
Investment Capital Program
Our 2020 investment capital program will accommodate a net investment level, inclusive of the $84 million to acquire the 20% interest in Saddlehorn, of approximately $220 to $260 million. The partnership has increased previously-issued 2020 investment capital guidance due to scope changes and phasing of investments from 2019 to 2020 as well as factoring higher cost assumptions to complete the projects.

50

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.
RESULTS OF OPERATIONS
Results of operations were as follows:
 
Year Ended December 31,
(in thousands)
2019
 
2018
 
2017
Revenues
 
 
 
 
 
Midstream Services — Affiliate
$
417,835

 
$
338,747

 
$
271,269

Midstream Services — Third Party
96,194

 
78,498

 
18,353

Crude Oil Sales — Third Party
189,772

 
141,490

 
—

Total Revenues
703,801

 
558,735

 
289,622

Costs and Expenses
 
 
 
 
 
Cost of Crude Oil Sales
181,390

 
136,368

 
—

Direct Operating
116,675

 
95,852

 
67,832

Depreciation and Amortization
96,981

 
79,568

 
22,990

General and Administrative
25,777

 
25,910

 
14,792

Other Operating (Income) Expense
(488
)
 
2,159

 
—

Total Operating Expenses
420,335

 
339,857

 
105,614

Operating Income
283,466

 
218,878

 
184,008

Other Expense (Income)
 
 
 
 
 
Interest Expense, Net of Amount Capitalized
16,236

 
10,447

 
1,603

Investment Loss (Income)
17,748

 
(16,289
)
 
(6,334
)
Total Other Expense (Income)
33,984

 
(5,842
)
 
(4,731
)
Income Before Income Taxes
249,482

 
224,720

 
188,739

Tax Provision
4,015

 
8,001

 
27,972

Net Income
245,467

 
216,719

 
160,767

Less: Net Income Prior to the Drop-Down and Simplification Transaction
12,929

 
27,843

 
(2,869
)
Net Income Subsequent to the Drop-Down and Simplification Transaction
232,538

 
188,876

 
163,636

Less: Net Income Attributable to Noncontrolling Interests
72,542

 
26,142

 
23,064

Net Income Attributable to Noble Midstream Partners LP
$
159,996

 
$
162,734

 
$
140,572

 
 
 
 
 
 
Adjusted EBITDA(1) Attributable to Noble Midstream Partners LP
$
254,586

 
$
223,144

 
$
156,526

 
 
 
 
 
 
Distributable Cash Flow(1) of Noble Midstream Partners LP
$
213,442

 
$
182,024

 
$
136,156

(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, see — Adjusted EBITDA (Non-GAAP Financial Measure), Distributable Cash Flow (Non-GAAP Financial Measure) and Reconciliation of Non-GAAP Financial Measures, below.

51

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.
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,
 
2019
 
2018
 
2017
DJ Basin
 
 
 
 
 
Crude Oil Sales Volumes (Bbl/d)
9,354

 
6,129

 
—

Crude Oil Gathering Volumes (Bbl/d)
182,121

 
143,095

 
61,864

Natural Gas Gathering Volumes (MMBtu/d)
476,605

 
308,929

 
228,768

Natural Gas Processing Volumes (MMBtu/d)
50,039

 
61,766

 
49,531

Produced Water Gathering Volumes (Bbl/d)
39,629

 
29,903

 
16,435

Fresh Water Delivery Volumes (Bbl/d)
164,524

 
175,754

 
155,990

 
 
 
 
 
 
Delaware Basin
 
 
 
 
 
Crude Oil Gathering Volumes (Bbl/d)
49,842

 
34,032

 
7,385

Natural Gas Gathering Volumes (MMBtu/d)
155,155

 
78,875

 
16,172

Produced Water Gathering Volumes (Bbl/d)
148,886

 
91,312

 
20,930

 
 
 
 
 
 
Total Gathering Systems
 
 
 
 
 
Crude Oil Sales Volumes (Bbl/d)
9,354

 
6,129

 
—

Crude Oil Gathering Volumes (Bbl/d)
231,963

 
177,127

 
69,249

Natural Gas Gathering Volumes (MMBtu/d)
631,760

 
387,804

 
244,940

Total Barrels of Oil Equivalent (Boe/d)
322,312

 
232,974

 
100,652

Natural Gas Processing Volumes (MMBtu/d)
50,039

 
61,766

 
49,531

Produced Water Gathering Volumes (Bbl/d)
188,515

 
121,215

 
37,365

 
 
 
 
 
 
Total Fresh Water Delivery
 
 
 
 
 
Fresh Water Services Volumes (Bbl/d)
164,524

 
175,754

 
155,990



52

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, except percentages)
2019
 
 
2018
 
 
2017
Year Ended December 31,
 
 
 
 
 
 
 
 
 
Gathering and Processing — Affiliate
$
337,086

 
27
 %
 
$
265,505

 
40
 %
 
$
189,732

Gathering and Processing — Third Party
76,645

 
42
 %
 
54,017

 
626
 %
 
7,444

Fresh Water Delivery — Affiliate
77,566

 
12
 %
 
69,266

 
(9
)%
 
75,860

Fresh Water Delivery — Third Party
12,591

 
(35
)%
 
19,345

 
77
 %
 
10,909

Crude Oil Sales — Third Party
189,772

 
34
 %
 
141,490

 
N/M

 
—

Other — Affiliate
3,183

 
(20
)%
 
3,976

 
(30
)%
 
5,677

Other — Third Party
6,958

 
35
 %
 
5,136

 
N/M

 
—

Total Midstream Services Revenues
$
703,801

 
26
 %
 
$
558,735

 
93
 %
 
$
289,622

N/M amount is not meaningful.
Revenues Trend Analysis
Revenues increased during 2019 as compared with 2018 and increased during 2018 as compared with 2017. The increases in revenues by reportable segment were as follows:
Gathering Systems Gathering Systems revenues increased by $143.5 million during 2019 as compared with 2018 due to the following:
•
an increase of $48.3 million in crude oil sales and $17.4 million in crude oil gathering services driven by an increase in throughput volumes resulting from an increase in the number of wells connected to the Black Diamond system;
•
an increase of $54.8 million in crude oil, produced water and natural gas gathering services revenues driven by an increase in throughput volumes resulting from an increase in wells connected to our gathering systems in the Wells Ranch IDP, Greeley Crescent IDP, and Mustang IDP.
•
an increase of $43.6 million in crude oil, natural gas and produced water gathering services revenues driven by an increase in throughput volumes resulting from an increase in wells connected to our gathering systems in the Delaware Basin;
partially offset by:
•
a decrease of $10.1 million in natural gas gathering and processing revenues driven by a decrease in natural gas throughput volumes in the East Pony IDP; and
•
a decrease of $7.2 million in crude oil gathering driven by a decrease in crude oil throughput volumes in the East Pony IDP.
Gathering Systems revenues increased by $267.3 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 Black Diamond’s and Greenfield Midstream, LLC’s (the “Greenfield Member”) 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;
•
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

53

•
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.
Fresh Water Delivery Fresh Water Delivery revenues increased by $1.5 million during 2019 as compared with 2018 due to the following:
•
an increase of $19.8 million in fresh water delivery revenues due to the recommencement of services in the East Pony IDP area during 2019;
substantially offset by:
•
a decrease of $18.3 million in fresh water delivery revenues in the Mustang IDP, Greeley Crescent IDP and Wells Ranch IDP driven by decreased fresh water volumes resulting from reduced well completion activity by Noble.
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.
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 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.
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; Nasdaq 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.

54

Costs and Expenses Trend Analysis
Costs and expenses were as follows:
 
 
 
Increase (Decrease)
from Prior Year
 
 
 
Increase
from Prior Year
 
 
(in thousands, except percentages)
2019
 
 
2018
 
 
2017
Year Ended December 31,
 
 
 
 
 
 
 
 
 
Cost of Crude Oil Sales
$
181,390

 
33
 %
 
$
136,368

 
N/M

 
$
—

Direct Operating
116,675

 
22
 %
 
95,852

 
41
%
 
67,832

Depreciation and Amortization
96,981

 
22
 %
 
79,568

 
246
%
 
22,990

General and Administrative
25,777

 
(1
)%
 
25,910

 
75
%
 
14,792

Other Operating (Income) Expense
(488
)
 
(123
)%
 
2,159

 
N/M

 
—

Total Operating Expenses
$
420,335

 
24
 %
 
$
339,857

 
222
%
 
$
105,614

N/M Amount is not meaningful
Cost of Crude Oil Sales Cost of crude oil sales is recorded within our Gathering Systems reportable segment. Cost of crude oil sales increased $45.0 million during 2019 as compared with 2018. The increase is primarily attributable to increased sales volumes resulting from an increase in the number of wells connected to the Black Diamond system.
Direct Operating Expenses Direct operating expenses increased during 2019 as compared with 2018 and increased during 2018 as compared with 2017. The increases in direct operating expenses by reportable segment were as follows:
Gathering Systems Gathering Systems direct operating expenses increased $15.9 million during 2019 as compared with 2018. The increase was primarily attributable to operating expenses associated with expanding our systems to gather increased volumes resulting from an increase in the number of wells connected in the Delaware Basin, Wells Ranch IDP, Greeley Crescent IDP, and Mustang IDP areas during 2019.
Gathering systems direct operating expenses increased $28.9 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.
Fresh Water Delivery Fresh Water Delivery direct operating expenses increased $4.4 million during 2019 as compared with 2018 primarily due to operating expenses associated with the recommencement of services in the East Pony IDP area.
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.
Corporate Corporate direct operating expenses increased $0.5 million during 2019 as compared with 2018 and $0.9 million during 2018 as compared with 2017 primarily due to increased insurance expense.
Depreciation and Amortization Depreciation and amortization expense increased during 2019 as compared with 2018 and increased during 2018 as compared with 2017. The increases by reportable segment were as follows:
Gathering Systems Gathering Systems depreciation and amortization expense increased $17.1 million during 2019 as compared with 2018 primarily due to assets placed in service in 2019. Assets placed in service were associated with the Mustang gathering system, the expansion of the Delaware Basin infrastructure, and the continued development of the Black Diamond system.
Gathering Systems depreciation and amortization expense increased $56.6 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.
Fresh Water Delivery Fresh Water Delivery depreciation and amortization expense remained consistent during 2019 as compared with 2018 as a substantial portion of the assets placed in service during 2019 were placed in service during fourth quarter 2019. Fresh Water Delivery depreciation and amortization expense remained consistent during 2018 as compared with 2017 as fresh water delivery assets in service remained consistent.

55

General and Administrative Expense General and administrative expense is recorded within our Corporate reportable segment. General and administrative expense remained consistent during 2019 as compared with 2018. The increase in transaction expenses incurred in connection with the Drop-Down and Simplification Transaction were offset by transactions expenses incurred in connection with the Black Diamond acquisition.
General and administrative expense increased $11.1 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 4. Offerings and Acquisition.
Other Operating Expense (Income) Other operating expense (income) 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 Expense (Income) Trend Analysis
 
 
 
Increase (Decrease)
from Prior Year
 
 
 
Increase from Prior Year
 
 
(in thousands)
2019
 
 
2018
 
 
2017
Year Ended December 31,
 
 
 
 
 
 
 
 
 
Interest Expense
$
33,723

 
100
 %
 
$
16,863

 
308
%
 
$
4,130

Capitalized Interest
(17,487
)
 
173
 %
 
(6,416
)
 
154
%
 
(2,527
)
Interest Expense, Net
16,236

 
55
 %
 
10,447

 
552
%
 
1,603

Investment Loss (Income)
17,748

 
(209
)%
 
(16,289
)
 
157
%
 
(6,334
)
Total Other Expense (Income)
$
33,984

 
(682
)%
 
$
(5,842
)
 
23
%
 
$
(4,731
)
Interest Expense, Net Interest expense is recorded within our Corporate reportable segment. Interest expense represents interest incurred in connection with our revolving credit facility and term loan credit facilities. 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 as well as our investments in equity method investees engaged in construction activities 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, 2019 and 2018 and See Item 8. Financial Statements and Supplementary Data – Note 6. Investments.
Interest expense increased $16.9 million during 2019 as compared with 2018. The increase was primarily due to increased outstanding long-term debt during 2019 as compared with 2018, partially offset by a decrease in interest rates. Capitalized interest increased $11.1 million during 2019 as compared with 2018, primarily attributable to capitalized interest associated with our capital contributions to Delaware Crossing, EPIC Y-Grade and EPIC Crude during 2019.
Interest expense increased $12.7 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 utilized proceeds from long-term debt to fund portions of our construction activities and the Black Diamond Acquisition. In addition, interest rates increased 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.
Investment Loss (Income)
Investment income is recorded within our Investments in Midstream Entities reportable segment. Investment income decreased $34.0 million during 2019 as compared with 2018 primarily driven by losses from the Delaware Crossing, EPIC Y-Grade and EPIC Crude investments attributable to expenses incurred in connection with the formation of the entities as well as general and administrate expenses incurred prior to service commencement. Earnings from Advantage also decreased in 2019 as compared to 2018 resulting from decreased crude oil throughput.
Investment income increased $10.0 million during 2018 as compared with 2017 due to higher earnings from our investment in Advantage resulting from increased crude oil throughput volumes during 2018 as compared with 2017 as well as a full period of activity from Advantage which closed during second quarter 2017.

56

Income Tax Provision
We are not a taxable entity for United States 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 we do not record deferred taxes related to the aggregate difference in the basis of our assets for financial and tax reporting purposes. We are subject to a Texas margin tax due to our operations in the Delaware Basin and we recorded a de minimis state tax provision for the years ended December 31, 2019 and December 31, 2018. For periods prior to the Drop-Down and Simplification Transaction, our consolidated financial statements include a provision for tax expense on income related to the assets contributed to the Partnership. See Item 8. Financial Statements and Supplementary Data – Note 16. 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.
As a result of our increased investment in midstream entities, we have refined our presentation of Adjusted EBITDA to adjust for certain items with respect to our equity method investments. We now define Adjusted EBITDA as net income 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. Additionally, Adjusted EBITDA reflects the adjusted earnings impact of our equity method investments by adjusting our equity earnings or losses from our equity method investments to reflect our proportionate share of the EBITDA of such equity method investments. The table below also reflects Adjusted EBITDA prior to Drop-Down and Simplification Transaction. Prior period Adjusted EBITDA has been reclassified to conform to the current period presentation.
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.
As a result of our increased investment in midstream entities, we have refined our presentation of distributable cash flow to adjust for certain items with respect to our equity method investments. We now define distributable cash flow as Adjusted EBITDA plus distributions received from our equity method investments less our proportionate share of Adjusted EBITDA from such equity method investments, estimated maintenance capital expenditures and cash interest paid. The table below also reflects Adjusted EBITDA prior to Drop-Down and Simplification Transaction. Prior period distributable cash flow has been reclassified to conform to the current period presentation.
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

57

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.
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,
(in thousands)
2019
 
2018
 
2017
Reconciliation from Net Income
 
 
 
 
 
Net Income
$
245,467

 
$
216,719

 
$
160,767

Add:
 
 
 
 
 
Depreciation and Amortization
96,981

 
79,568

 
22,990

Interest Expense, Net of Amount Capitalized
16,236

 
10,447

 
1,603

Tax Provision
4,015

 
8,001

 
27,972

Transaction and Integration Expenses
6,338

 
7,601

 
—

Proportionate Share of Equity Method Investment EBITDA Adjustments
16,160

 
1,700

 
2,017

Unit-Based Compensation and Other
751

 
2,392

 
790

Adjusted EBITDA
385,948

 
326,428

 
216,139

Less:
 
 
 
 
 
Adjusted EBITDA Prior to Drop-Down and Simplification Transaction
26,629

 
49,832

 
35,120

Adjusted EBITDA Subsequent to Drop-Down and Simplification Transaction
359,319

 
276,596

 
181,019

Less:
 
 
 
 
 
Adjusted EBITDA Attributable to Noncontrolling Interests
104,733

 
53,452

 
24,493

Adjusted EBITDA Attributable to Noble Midstream Partners LP
254,586

 
223,144

 
156,526

Add:
 
 
 
 
 
Distribution from Equity Method Investments
10,135

 
9,219

 
—

Less:
 
 
 
 
 
Proportionate Share of Equity Method Investment Adjusted EBITDA
(6,275
)
 
13,580

 
3,796

Cash Interest Paid
32,984

 
16,320

 
3,734

Maintenance Capital Expenditures
24,570

 
20,439

 
12,840

Distributable Cash Flow of Noble Midstream Partners LP
$
213,442

 
$
182,024

 
$
136,156


58

Reconciliation of Net Cash Provided by Operating Activities to Adjusted EBITDA and Distributable Cash Flow
 
Year Ended December 31,
(in thousands)
2019
 
2018
 
2017
Reconciliation from Net Cash Provided by Operating Activities
 
 
 
 
 
Net Cash Provided by Operating Activities
$
385,143

 
$
273,687

 
$
196,362

Add:
 
 
 
 
 
Interest Expense, Net of Amount Capitalized
16,236

 
10,447

 
1,603

Changes in Operating Assets and Liabilities
(4,165
)
 
33,320

 
14,742

Transaction and Integration Expenses
6,338

 
7,601

 
—

Equity Method Investment EBITDA Adjustments
(16,413
)
 
4,361

 
3,796

Other Adjustments
(1,191
)
 
(2,988
)
 
(364
)
Adjusted EBITDA
385,948

 
326,428

 
216,139

Less:
 
 
 
 
 
Adjusted EBITDA Prior to Drop-Down and Simplification Transaction
26,629

 
49,832

 
35,120

Adjusted EBITDA Subsequent to Drop-Down and Simplification Transaction
359,319

 
276,596

 
181,019

Less:
 
 
 
 
 
Adjusted EBITDA Attributable to Noncontrolling Interests
104,733

 
53,452

 
24,493

Adjusted EBITDA Attributable to Noble Midstream Partners LP
254,586

 
223,144

 
156,526

Add:
 
 
 
 
 
Distribution from Equity Method Investments
10,135

 
9,219

 
—

Less:
 
 
 
 
 
Proportionate Share of Equity Method Investment Adjusted EBITDA
(6,275
)
 
13,580

 
3,796

Cash Interest Paid
32,984

 
16,320

 
3,734

Maintenance Capital Expenditures
24,570

 
20,439

 
12,840

Distributable Cash Flow of Noble Midstream Partners LP
$
213,442

 
$
182,024

 
$
136,156



59

LIQUIDITY AND CAPITAL RESOURCES
Financing Strategy
Our primary sources 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.
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 2019, we utilized external financing sources to fund portions of our construction activities, capital contributions to our investments and cash consideration for the Drop-Down and Simplification Transaction. See Item 8. Financial Statements and Supplementary Data – Note 4. Offerings and Acquisition and Item 8. Financial Statements and Supplementary Data – Note 6. Investments.
Available Liquidity
Our operating cash flows are a significant source of liquidity. Additional sources of funding were available through debt and equity financing activities, as described below. Year-end liquidity was as follows:
 
December 31,
(in thousands)
2019
 
2018
 
2017
Cash, Cash Equivalents, and Restricted Cash (1)
$
12,726

 
$
15,712

 
$
57,595

Amount Available to be Borrowed Under Our Revolving Credit Facility (2)
555,000

 
740,000

 
265,000

Available Liquidity
$
567,726

 
$
755,712

 
$
322,595

(1) 
See Item 8. Financial Statements and Supplementary Data – Note 2. Summary of Significant Accounting Policies and Basis of Presentation.
(2) 
Revolving Credit Facility and Term Loan Credit Facility
Our revolving credit facility is available to fund working capital requirements, acquisitions and expansion capital expenditures. In 2019, we utilized our revolving credit facility to fund our capital contributions to Delaware Crossing, EPIC Y-Grade and EPIC Crude and a portion of the cash consideration in the Drop-Down and Simplification Transaction. On December 13, 2019, we exercised the $350 million accordion feature on the revolving credit facility and increased the capacity from $800 million to $1.15 billion. As of December 31, 2019, $595 million was outstanding under our revolving credit facility. See Item 8. Financial Statements and Supplementary Data – Note 8. Long-Term Debt.
On August 23, 2019, we entered into an additional three-year senior unsecured term loan credit facility that permits aggregate borrowings of up to $400 million. Proceeds were 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.
Preferred Equity
On March 25, 2019, we secured the GIP preferred equity commitment totaling $200 million. During 2019, preferred equity proceeds totaled $100 million and we incurred offering costs of $3.4 million. The remaining $100 million equity commitment is available for a one-year period, subject to certain conditions precedent. Proceeds from the preferred equity were utilized to repay a portion of outstanding borrowings under our revolving credit facility. See Item 8. Financial Statements and Supplementary Data – Note 4. Offerings and Acquisition.
2019 Private Placement
On November 14, 2019, we completed the 2019 Private Placement and sold 12,077,295 Common Units for gross proceeds of approximately $250 million. Net proceeds totaled approximately $242.9 million, after deducting offering expenses of approximately $7.1 million. Proceeds from the 2019 Private Placement were utilized to fund a portion of the cash consideration for the Drop-Down and Simplification Transaction. See Item 8. Financial Statements and Supplementary Data – Note 4. Offerings and Acquisition.


60

Cash Flows
Summary cash flow information was as follows:
 
Year Ended December 31,
(in thousands)
2019
 
2018
 
2017
Total Cash Provided By (Used in)
 
 
 
 
 
Operating Activities
$
385,143

 
$
273,687

 
$
196,362

Investing Activities
(872,593
)
 
(1,268,488
)
 
(381,745
)
Financing Activities
484,464

 
952,918

 
185,535

(Decrease) Increase in Cash and Cash Equivalents
$
(2,986
)
 
$
(41,883
)
 
$
152

Operating Activities Net cash provided by operating activities increased during 2019 as compared with 2018 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.
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.
Investing Activities Cash used in investing activities decreased during 2019 as compared with 2018 primarily due to the Black Diamond Acquisition and increased additions to property, plant and equipment during 2018 related to construction of the Mustang gathering system, expansion of the Mustang fresh water delivery system and construction of the Delaware Basin CGFs.
The decrease was partially offset by our additions to investments during 2019 due to our capital contributions to Delaware Crossing, EPIC Y-Grade and EPIC Crude.
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.
Financing Activities Cash provided by financing activities decreased during 2019 as compared with 2018 primarily due to the distribution to Noble for the Drop-Down and Simplification Transaction, a decrease in contributions from noncontrolling interest holders and an increase in distributions to unitholders. The decrease was partially offset by an increase in net long-term borrowings, proceeds from the preferred equity issuance and other equity offerings.
Cash provided by financing activities increased during 2018 as compared with 2017. The increase was primarily due to increased net long-term debt borrowings and increased contributions from noncontrolling interest owners, which included the contribution from Greenfield Member to fund the Black Diamond Acquisition.
Off-Balance Sheet Arrangements
As of December 31, 2019, our material off-balance sheet arrangements that we have entered into include our transportation commitments, undrawn letters of credit and guarantees.

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Contractual Obligations
The following table summarizes certain contractual obligations as of December 31, 2019 that are reflected in the consolidated balance sheets and/or disclosed in the accompanying notes.
Obligation
Note Reference (1)
 
2020
 
2021 and 2022
 
2023 and 2024
 
2025 and Beyond
 
Total
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
Long-Term Debt (2)
 
$
—

 
$
900,000

 
$
595,000

 
$
—

 
$
1,495,000

Long-Term Debt Interest Payments and Revolving Credit Facility Commitment Fee (3)
 
45,221

 
66,253

 
3,677

 
—

 
115,151

Asset Retirement Obligations (4)
 
—

 
—

 
8,461

 
29,381

 
37,842

Omnibus Fee (5)
 
6,850

 
—

 
—

 
—

 
6,850

Finance Lease Obligations (6)
 
—

 
2,005

 
—

 
—

 
2,005

Operating Lease Obligations (7)
 
2,528

 
260

 
—

 
—

 
2,788

Purchase Obligations (8)
 
4,947

 
—

 
—

 
—

 
4,947

Transportation Fees (9)
 
17,961

 
67,296

 
70,552

 
60,809

 
216,618

Surface Lease Obligations (10)
 
215

 
391

 
350

 
3,857

 
4,813

Total Contractual Obligations
 
 
$
77,722

 
$
1,036,205

 
$
678,040

 
$
94,047

 
$
1,886,014

(1) 
References are to the Notes accompanying Item 8. Financial Statements and Supplementary Data.
(2) 
Long-term debt includes our revolving credit facility and term loan credit facility balances based on the maturity dates of the facilities.
(3) 
Interest payments are based on the outstanding balance, scheduled maturity and interest rate in effect at December 31, 2019. 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, 2019, $555 million, for all periods presented and assumes no borrowing capacity increases.
(4) 
Asset retirement obligations are discounted.
(5) 
Annual general and administrative fee we pay to Noble for certain administrative and operational support services being provided to us. The cap on the initial rate expired in September 2019 and we have commenced the annual redetermination process.
(6) 
Annual capital lease payments exclude regular maintenance and operational costs.
(7) 
Operating lease obligations represent non-cancelable leases for equipment used in our daily operations. Amounts have not been discounted.
(8) 
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.
(9) 
Our transportation fees include fixed fees for the transportation of crude oil. We have entered into long-term agreements with unaffiliated third parties to satisfy a substantial portion of our transportation commitment.
(10) 
Surface lease obligations represent annual payments to landowners.
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.
Preferred Equity We can redeem the preferred equity in whole or in part at any time for cash at a predetermined redemption price. The predetermined redemption price is the greater of (i) an amount necessary to achieve a 12% internal rate of return or (ii) an amount necessary to achieve a 1.375x multiple on invested capital. GIP can request redemption of the preferred equity following the later of the sixth anniversary of the closing or the fifth anniversary of the EPIC Crude pipeline completion date at a pre-determined base return. The preferred equity is perpetual and has a 6.5% annual dividend rate, payable quarterly in cash, with the ability to accrue unpaid dividends during the first two years following the closing.See Item 8. Financial Statements and Supplementary Data – Note 2. Summary of Significant Accounting Policies and Basis of Presentation and Note 4. Offerings and Acquisition.
Letters of Credit In the ordinary course of business, we maintain letters of credit in support of certain performance obligations of our subsidiaries. Outstanding letters of credit, including Black Diamond, totaled approximately $42.4 million at December 31, 2019.
Capital Requirements
Capital Expenditures and Planned Capital Expenditures

62

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, 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 and our third-party customers’ 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)
2019
 
2018
 
2017
Gathering System Expenditures (1)
$
257,066

 
$
738,427

 
$
393,184

Fresh Water Delivery System Expenditures
7,330

 
23,018

 
16,469

Other
1,068

 
555

 
—

Total Capital Expenditures
$
265,464

 
$
762,000

 
$
409,653

 
 
 
 
 
 
Additions to Investments
$
611,325

 
$
426

 
$
68,504

(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, 2019, gathering system expenditures were primarily associated with well connections in the Mustang IDP, Black Diamond dedication area and the Delaware Basin as well as expansion of the Mustang gathering system. Fresh water delivery system expenditures were primarily associated with the expansion of the Greeley Crescent fresh water delivery system. Our additions to investments were primarily related to our capital contributions for the Delaware Crossing, EPIC Y-Grade and EPIC Crude. See Item 8. Financial Statements and Supplementary Data - Note 6 Investments.
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 Advantage.
Cash Distributions
Our partnership agreement requires that we distribute all of our available cash quarterly. 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 23, 2020, the Board of our General Partner declared a quarterly cash distribution of $0.6878 per limited partner unit. The distribution will be paid on February 14, 2020, to unitholders of record on February 4, 2020.
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

63

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 4. Offerings and 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 Gunnison River DevCo LP 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.
We use the equity method of accounting for investments in entities that we do not control but over which we exert significant influence. For certain entities, we serve as the operator and exert significant influence over the day-to-day operations. For other entities, we do not serve as the operator; however, our voting position on management committees or the board of directors allows us to exert significant influence over decisions regarding capital investments, budgets, turnarounds, maintenance, monetization decisions and other project matters. As a result, our investments in Advantage, Delaware Crossing, EPIC Y-Grade and EPIC Crude do not require consolidation under the VIE consolidation model. 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 6. Investments.
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.

64

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, sustained decreases in commodity prices, significant changes in Noble’s future development plans, to the extent they affect our operations, may necessitate assessment of the carrying amount of our affected assets for recoverability. In addition, an increase in our construction or operating costs may also necessitate an assessment.
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. 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 4. Offerings and 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, 2019. 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 4. Offerings and Acquisition and see Item 8. Financial Statements and Supplementary Data – Note 7. Intangible Assets.


65

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 process 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 facilities, which have variable interest rates. As of December 31, 2019, $595 million and $900 million were outstanding under our revolving credit facility and term loan credit facilities, respectively. A 1.0% increase in our interest rates would have resulted in an estimated $9.5 million increase in interest expense for the year ended December 31, 2019. 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.
LIBOR Transition
The London Inter-bank Offered Rate (“LIBOR”) is a commonly used indicative measure of the average interest rate at which major global banks could borrow from one another. Certain of our agreements use LIBOR as a “benchmark” or “reference rate” for various terms. It is expected that the LIBOR benchmark will be discontinued after 2021. We are currently reviewing our agreements that extend past 2021 to determine their exposure to LIBOR. Some agreements contain an existing LIBOR alternative. Where there is not an alternative, we expect to replace the LIBOR benchmark with an alternative reference rate such as the Secured Overnight Financing Rate (“SOFR”). We do not expect the transition to an alternative rate to have a significant impact on our business or operations.
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.
Additionally, we are subject to the risk of non-payment or non-performance by our customers, including with respect to our commercial agreements, most of which do not contain minimum volume commitments. Furthermore, we cannot predict the extent to which our customers’ businesses would be impacted if conditions in the energy industry were to deteriorate nor can we estimate the impact such conditions would have on our customers’ 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 our customers 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.

66

Item 8. Financial Statements and Supplementary Data
INDEX TO FINANCIAL STATEMENTS
Consolidated Financial Statements of Noble Midstream Partners LP
 
 
 
68
 
 
69
 
 
71
 
 
72
 
 
73
 
 
74
 
 
75
 
 
 
 
 
76
77
83
85
87
88
90
91
92
92
94
94
95
96
97
98
 
 
99


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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, 2019, 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, 2019, 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, 2019 which is included herein.
 
 
 
 
Noble Midstream Partners LP


68

Report of Independent Registered Public Accounting Firm

To the Unitholders of Noble Midstream Partners LP and
Board of Directors of Noble Midstream GP LLC:
Opinion on the Consolidated Financial Statements
We have audited the accompanying consolidated balance sheets of Noble Midstream Partners LP and subsidiaries (the Partnership) as of December 31, 2019 and 2018, the related consolidated statements of operations and comprehensive income, cash flows, and changes in equity for each of the years in the three‑year period ended December 31, 2019, 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, 2019 and 2018, and the results of its operations and its cash flows for each of the years in the three‑year period ended December 31, 2019, 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, 2019, 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 12, 2020 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.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgment. The communication of a critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Assessment of property, plant and equipment for impairment triggering events
As discussed in Note 2 to the consolidated financial statements, the Partnership performs a quarterly assessment of property, plant and equipment to identify events or changes in circumstances, or triggering events, which indicate the carrying value of such assets may not be recoverable. The Partnership provides midstream services to Noble Energy, Inc. and other third party customers via long-term revenue agreements. Triggering events include sustained decreases in commodity prices, declines in customers’ reservoir performance or changes to their development outlook, and increased construction and operating costs. The carrying value of property, plant and equipment as of December 31, 2019 was $1,762,957 thousand.
We identified the assessment of property, plant and equipment for impairment triggering events as a critical audit matter. Sustained decreases in commodity prices, declines in customers’ reservoir performance or changes to their development outlook, and increased construction and operating costs could significantly impact the future profitability of the Partnership, and the evaluation of these factors required a higher degree of auditor judgment.
The primary procedures we performed to address this critical audit matter included the following. We tested certain internal controls over the Partnership’s process to identify and assess triggering events, including controls related to

69

the consideration of actual revenue generated under existing revenue agreements, commodity prices, customers’ reservoir performance and their development plans, and historical financial results of the Partnership. We evaluated the Partnership’s triggering event identification and assessment against internal operational data and financial results. We compared the Partnership’s estimated production information against customers’ reserves estimates and development outlooks. We tested a sample of revenue transactions and compared those transactions to the underlying revenue agreements to identify significant modifications to the revenue agreements. We evaluated the Partnership’s data and assumptions when we identified information that was contrary to that used by the Partnership.

 
 
/s/ KPMG LLP
 
 
 
 
 
 
 
We have served as the Partnership’s auditor since 2015.
 
 
 
 
 
Houston, Texas
 
 
 
 
February 12, 2020
 
 
 
 


70

Report of Independent Registered Public Accounting Firm

To the Unitholders of Noble Midstream Partners LP and
Board of Directors of Noble Midstream GP LLC:
Opinion on Internal Control Over Financial Reporting
We have audited Noble Midstream Partners LP and subsidiaries’ (the Partnership) internal control over financial reporting as of December 31, 2019, 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, 2019, 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, 2019 and 2018, the related consolidated statements of operations and comprehensive income, cash flows, and changes in equity for each of the years in the three-year period ended December 31, 2019, and the related notes (collectively, the consolidated financial statements), and our report dated February 12, 2020 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 12, 2020
 
 
 
 


71


Noble Midstream Partners LP
Consolidated Balance Sheets
(in thousands)
 
December 31,
2019
 
December 31,
2018
ASSETS
 
 
 
Current Assets
 
 
 
Cash and Cash Equivalents
$
12,676

 
$
14,761

Accounts Receivable — Affiliate
42,428

 
41,812

Accounts Receivable — Third Party
44,093

 
23,459

Other Current Assets
8,730

 
5,875

Total Current Assets
107,927

 
85,907

Property, Plant and Equipment
 
 
 
Total Property, Plant and Equipment, Gross
2,006,995

 
1,752,122

Less: Accumulated Depreciation and Amortization
(244,038
)
 
(181,199
)
Total Property, Plant and Equipment, Net
1,762,957

 
1,570,923

Investments
660,778

 
82,317

Intangible Assets, Net
277,900

 
310,202

Goodwill
109,734

 
109,734

Other Noncurrent Assets
6,786

 
33,095

Total Assets
$
2,926,082

 
$
2,192,178

LIABILITIES, MEZZANINE EQUITY AND EQUITY
 
 
 
Current Liabilities
 
 
 
Accounts Payable — Affiliate
$
8,155

 
$
7,182

Accounts Payable — Trade
107,705

 
94,265

Other Current Liabilities
11,680

 
13,790

Total Current Liabilities
127,540

 
115,237

Long-Term Liabilities
 
 
 
Long-Term Debt
1,495,679

 
559,021

  Asset Retirement Obligations
37,842

 
30,533

Other Long-Term Liabilities
4,160

 
832

Total Liabilities
1,665,221

 
705,623

Mezzanine Equity
 
 
 
Redeemable Noncontrolling Interest, Net
106,005

 
—

Equity
 
 
 
Parent Net Investment
—

 
170,322

Partners’ Equity
 
 
 
Limited Partner
 
 
 
Common Units (90,136 and 23,759 units outstanding, respectively)
813,999


699,866

Subordinated Units (15,903 units outstanding as of December 31, 2018)
—

 
(130,207
)
General Partner
—

 
2,421

Total Partners’ Equity and Parent Net Investment
813,999

 
742,402

Noncontrolling Interests
340,857

 
744,153

Total Equity
1,154,856

 
1,486,555

Total Liabilities, Mezzanine Equity and Equity
$
2,926,082

 
$
2,192,178

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

72

Noble Midstream Partners LP
Consolidated Statements of Operations and Comprehensive Income
(in thousands, except per unit amounts)
 
Year Ended December 31,
 
2019

2018
 
2017
Revenues





 
 
Midstream Services — Affiliate
$
417,835


$
338,747

 
$
271,269

Midstream Services — Third Party
96,194


78,498

 
18,353

Crude Oil Sales — Third Party
189,772

 
141,490

 
—

Total Revenues
703,801


558,735

 
289,622

Costs and Expenses
 
 
 
 
 
Cost of Crude Oil Sales
181,390

 
136,368

 
—

Direct Operating
116,675


95,852

 
67,832

Depreciation and Amortization
96,981


79,568

 
22,990

General and Administrative
25,777


25,910

 
14,792

Other Operating (Income) Expense
(488
)
 
2,159

 
—

Total Operating Expenses
420,335


339,857

 
105,614

Operating Income
283,466


218,878

 
184,008

Other Expense (Income)
 
 
 
 
 
Interest Expense, Net of Amount Capitalized
16,236


10,447

 
1,603

Investment Loss (Income)
17,748

 
(16,289
)
 
(6,334
)
Total Other Expense (Income)
33,984


(5,842
)
 
(4,731
)
Income Before Income Taxes
249,482


224,720

 
188,739

Tax Provision
4,015


8,001

 
27,972

Net Income
245,467


216,719

 
160,767

Less: Net Income Prior to the Drop-Down and Simplification Transaction
12,929

 
27,843

 
(2,869
)
Net Income Subsequent to the Drop-Down and Simplification Transaction
232,538

 
188,876

 
163,636

Less: Net Income Attributable to Noncontrolling Interests
72,542

 
26,142

 
23,064

Net Income Attributable to Noble Midstream Partners LP
159,996

 
162,734

 
140,572

Less: Net Income Attributable to Incentive Distribution Rights
13,967

 
5,836

 
835

Net Income Attributable to Limited Partners
$
146,029

 
$
156,898

 
$
139,737

 
 
 
 
 
 
Net Income Attributable to Limited Partners Per Limited Partner Unit — Basic
 
 
 
 
 
Common Units
$
3.09

 
$
3.96

 
$
4.10

Subordinated Units
$
3.86

 
$
3.96

 
$
4.10

 
 
 
 
 
 
Net Income Attributable to Limited Partners Per Limited Partner Unit — Diluted
 
 
 
 
 
Common Units
$
3.08

 
$
3.96

 
$
4.10

Subordinated Units
$
3.86

 
$
3.96

 
$
4.10

 
 
 
 
 
 
Weighted Average Limited Partner Units Outstanding — Basic
 
 
 
 
 
Common Units
40,083

 
23,686

 
18,192

Subordinated Units
5,795

 
15,903

 
15,903

 
 
 
 
 
 
Weighted Average Limited Partner Units Outstanding — Diluted
 
 
 
 
 
Common Units
40,105

 
23,701

 
18,204

Subordinated Units
5,795

 
15,903

 
15,903


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

73

Noble Midstream Partners LP
Consolidated Statements of Cash Flows
(in thousands)
 
Year Ended December 31,
 
2019
 
2018
 
2017
Cash Flows From Operating Activities
 
 
 
 
 
Net Income
$
245,467

 
$
216,719

 
$
160,767

Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities
 
 
 
 
 
Depreciation and Amortization
96,981

 
79,568

 
22,990

Asset Impairment
(488
)
 
3,470

 
—

Deferred Income Taxes
3,848

 
7,780

 
27,952

Loss (Income) from Equity Method Investees
22,435

 
(11,880
)
 
(1,779
)
Distributions from Equity Method Investees
10,135

 
9,219

 
—

Unit-Based Compensation
1,052

 
1,392

 
790

Other Adjustments for Noncash Items Included in Income
1,548

 
739

 
384

Changes in Operating Assets and Liabilities, Net of Assets Acquired and Liabilities Assumed
 
 
 
 
 
Increase in Accounts Receivable
(24,126
)
 
(13,863
)
 
(17,811
)
Increase (Decrease) in Accounts Payable
28,755

 
(22,101
)
 
1,580

Other Operating Assets and Liabilities, Net
(464
)
 
2,644

 
1,489

Net Cash Provided by Operating Activities
385,143

 
273,687

 
196,362

Cash Flows From Investing Activities
 
 
 
 
 
Additions to Property, Plant and Equipment
(262,342
)
 
(619,517
)
 
(314,214
)
Black Diamond Acquisition, Net of Cash Acquired
—

 
(649,868
)
 
—

Additions to Investments
(611,325
)
 
(426
)
 
(68,504
)
Distributions from Cost Method Investee and Other
1,074

 
1,323

 
973

Net Cash Used in Investing Activities
(872,593
)
 
(1,268,488
)
 
(381,745
)
Cash Flows From Financing Activities
 
 
 
 
 
Distributions to Noncontrolling Interests and Parent
(57,071
)
 
(38,056
)
 
(46,066
)
Contributions from Noncontrolling Interests
55,481

 
605,864

 
140,471

Borrowings Under Revolving Credit Facility
1,290,000

 
777,000

 
325,000

Repayment of Revolving Credit Facility
(755,000
)
 
(802,000
)
 
(240,000
)
Proceeds from Term Loan Credit Facilities
400,000

 
500,000

 
—

Proceeds from Preferred Equity, Net of Issuance Costs
97,198

 
—

 
—

Proceeds from Equity Offerings, Net of Issuance Costs
242,770

 
—

 
312,579

Distribution to Noble for Common Control Transactions
(670,000
)
 
—

 
(245,000
)
Distributions to Unitholders
(115,935
)
 
(86,841
)
 
(59,917
)
Debt Issuance Costs and Other
(2,979
)
 
(3,049
)
 
(1,532
)
Net Cash Provided by Financing Activities
484,464

 
952,918

 
185,535

(Decrease) Increase in Cash, Cash Equivalents, and Restricted Cash
(2,986
)
 
(41,883
)
 
152

Cash, Cash Equivalents, and Restricted Cash at Beginning of Period (1)
15,712

 
57,595

 
57,443

Cash, Cash Equivalents, and Restricted Cash at End of Period (1)
$
12,726

 
$
15,712

 
$
57,595

(1) 

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

74

Noble Midstream Partners LP
Consolidated Statements of Changes in Equity
(in thousands)
 
 
 
Partners’ Equity
 
 
 
Parent Net Investment
 
Common Units
Subordinated Units
General Partner
Noncontrolling Interests
Total
December 31, 2016
$
144,157

 
$
308,338

$
(36,799
)
$
—

$
71,366

$
487,062

Net Income
(2,869
)
 
75,076

64,661

835

23,064

160,767

Contributions from Noncontrolling Interests and Parent
58,678

 
—

—

—

123,381

182,059

Distributions to Noncontrolling Interests and Parent
(29,537
)
 
—

—

—

(21,737
)
(51,274
)
Distributions to Unitholders
—

 
(31,672
)
(27,930
)
(315
)
—

(59,917
)
Net Proceeds from Offerings
—

 
312,172

—

—

—

312,172

Distribution to Noble for Contributed Assets (1)
—

 
(28,459
)
(216,541
)
—

—

(245,000
)
Contributed Assets Transfer from Noble
—

 
6,371

48,473

—

(54,844
)
—

Unit-Based Compensation and Other
—

 
790

—

—

—

790

December 31, 2017
$
170,429

 
$
642,616

$
(168,136
)
$
520

$
141,230

$
786,659

Net Income
27,843

 
93,875

63,023

5,836

26,142

216,719

Contributions from Noncontrolling Interests and Parent
849

 
—

—

—

605,864

606,713

Distributions to Noncontrolling Interests and Parent
(28,799
)
 
—

—

—

(9,257
)
(38,056
)
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
—

 
1,361

—

—

—

1,361

December 31, 2018
$
170,322

 
$
699,866

$
(130,207
)
$
2,421

$
744,153

$
1,486,555

Net Income
12,929

 
123,662

22,367

13,967

72,542

245,467

Contributions from Noncontrolling Interests and Parent
—

 
—

—

—

55,481

55,481

Distributions to Noncontrolling Interests and Parent (3)
(54,889
)
 
—

—

—

(26,103
)
(80,992
)
Distributions to Unitholders
—

 
(80,480
)
(19,067
)
(16,388
)
—

(115,935
)
Black Diamond Equity Ownership Promote Vesting (2)
—

 
17,645

2,746

—

(20,391
)
—

Conversion of Subordinated Units to Common Units (4)
—

 
(124,161
)
124,161

—

—

—

Preferred Equity Accretion
—

 
(9,440
)
—

—

—

(9,440
)
Net Proceeds from Offerings
—

 
242,770

—

—

—

242,770

Distribution to Noble for Drop-Down and Simplification Transaction (1)
—

 
(670,000
)
—

—

—

(670,000
)
Asset Transfers for Drop-Down and Simplification Transaction
(128,362
)
 
613,187

—

—

(484,825
)
—

Unit-Based Compensation and Other
—

 
950

—

—

—

950

December 31, 2019
$
—

 
$
813,999

$
—

$
—

$
340,857

$
1,154,856


(1) 
See Note 3. Transactions with Affiliates for further discussion of our common control transactions.
(2) 
See Note 2. Summary of Significant Accounting Policies and Basis of Presentation for further discussion of the Black Diamond equity ownership promote vesting.
(3) 
Includes the elimination of a deferred tax asset and current tax liability associated with the Drop-Down and Simplification Transaction. See Note 2. Summary of Significant Accounting Policies and Basis of Presentation for further discussion.
(4) 
See Note 12. Partnership Distributions for further discussion on the conversion of Subordinated Units.

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

75
Noble Midstream Partners LP
 
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.
Partnership Assets Our assets consist of ownership interests in certain companies which serve specific areas and integrated development plan (“IDP”) areas and consist of the following:
Company
Areas Served
NBLX Dedicated Service
NBLX Ownership
Noncontrolling Interest(1)
Colorado River LLC (2)

Wells Ranch IDP (DJ Basin)


East Pony IDP (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 LLC (2)
East Pony IDP (DJ Basin)
Water Services
100%
N/A
Green River DevCo LLC (2)
Mustang IDP (DJ Basin)
Crude Oil Gathering
Natural Gas Gathering
Water Services
100%
N/A
Laramie River LLC (2)
Greeley Crescent IDP (DJ Basin)
Crude Oil Gathering
Water Services
100%
N/A
Black Diamond Dedication Area (DJ Basin)
Crude Oil Gathering
Crude Oil Sales
Natural Gas Gathering
54.4%
45.6%
Blanco River LLC (2)
Delaware Basin
Crude Oil Gathering
Natural Gas Gathering
Water Services
100%
N/A
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
Dos Rios DevCo LLC (5)
Delaware Basin
Crude Oil Transmission
Y-Grade Transmission
100%
N/A
Noble Midstream Holdings LLC
East Pony IDP (DJ Basin)
Natural Gas Gathering
Natural Gas Processing
100%
N/A
Delaware Basin
Crude Oil Gathering
Natural Gas Gathering
Water Services
100%
N/A
(1) 
The noncontrolling interest represents Noble’s retained ownership interest in the Gunnison River DevCo LP. The noncontrolling interest in Black Diamond represents Greenfield Member’s interest in Black Diamond.
(2) 
On December 31, 2019, the general partner and limited partnership of each of the companies were merged into a limited liability company (“LLC”).
(3) 
The Bronco IDP is a future development area. We currently have no midstream infrastructure assets in the Bronco IDP.
(4) 
Our interest in Advantage Pipeline L.L.C. (“Advantage”) is owned through Trinity River DevCo LLC.
(5) 
Our ownership interests in Delaware Crossing, EPIC Y-Grade and EPIC Crude are owned through wholly-owned subsidiaries of Dos Rios DevCo LLC.
Nature of Operations We operate and own interests in the following assets:
•
crude oil gathering systems;
•
natural gas gathering and processing systems and compression units;
•
crude oil treating facilities;
•
produced water collection, gathering, and cleaning systems;
•
fresh water storage and delivery systems; and
•
investments in midstream entities that provide transportation services.
We generate revenues primarily by charging fees on a per unit basis for gathering crude oil, gathering and processing natural gas, delivering and storing fresh water and collecting, cleaning and disposing of produced water. Additionally, we purchase

76
Noble Midstream Partners LP
 
Notes to Consolidated Financial Statements
 


crude oil from producers and sell crude oil to customers at various delivery points. 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 3. Transactions with Affiliates.
Note 2. Summary of Significant Accounting Policies and Basis of Presentation
Basis of Presentation and Consolidation   Our consolidated financial statements were prepared in accordance with accounting principles generally accepted in the United States (“U.S. GAAP”). 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 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. All financial statement activity associated with Black Diamond is captured within the Gathering Systems reportable segment. See Note 10. Segment Information.
Drop-Down and Simplification Transaction On November 21, 2019, we closed the Drop-Down and Simplification Transaction with Noble, as described in Note 3. Transactions with Affiliates. The Drop-Down and Simplification Transaction represented a transaction between entities under common control. Prior to the acquisition of the remaining limited partner interests in Blanco River DevCo LP, Green River DevCo LP and San Juan River DevCo LP, the interests were reflected as noncontrolling interests in the Partnership’s consolidated financial statements. As we acquired additional interests in already-consolidated entities, the acquisition of these interests did not result in a change in reporting entity, as defined under Financial Accounting Standards Board (“FASB”) Accounting Standards Codification Topic 805, Business Combinations. Therefore, results of operations related to these entities will be accounted for on a prospective basis.
Conversely, the acquisition of all of the issued and outstanding limited liability company interests of NBL Holdings is characterized as a change in reporting entity, as defined under FASB Accounting Standards Codification Topic 805, Business Combinations, as this entity previously had not been consolidated by us. Therefore, results of operations related to NBL Holdings have been accounted for on a retrospective basis. Our financial information has been recast to include the historical results of NBL Holdings for all periods presented. The financial statements of NBL Holdings for periods prior to the Drop-Down and Simplification Transaction have been prepared from the separate records maintained by Noble and may not necessarily be indicative of the results of operations had these entities operated on a consolidated basis during those periods. Because a direct ownership relationship did not exist among the Partnership and NBL Holdings prior to the Drop-Down and Simplification Transaction, the net investment in NBL Holdings is shown as Parent Net Investment, in lieu of partners’ equity, in the accompanying Consolidated Statement of Changes in Equity for periods prior to the Drop-Down and Simplification Transaction.
Equity Method of Accounting We use the equity method of accounting for investments in entities that we do not control but over which we exert significant influence. For certain entities, we serve as the operator and exert significant influence over the day-to-day operations. For other entities, we do not serve as the operator; however, our voting position on management committees or the board of directors allows us to exert significant influence over decisions regarding capital investments, budgets, turnarounds, maintenance, monetization decisions and other project matters. 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 6. 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 6. Investments.
Redeemable Noncontrolling Interest Our redeemable noncontrolling interest is related to our preferred equity issuance. We can redeem the preferred equity in whole or in part at any time for cash at a predetermined redemption price. The predetermined redemption price is the greater of (i) an amount necessary to achieve a 12% internal rate of return or (ii) an amount necessary to achieve a 1.375x multiple on invested capital. GIP can request redemption of the preferred equity following the later of the sixth anniversary of the closing or the fifth anniversary of the EPIC Crude pipeline completion date at a pre-determined base return. As GIP’s redemption right is outside of our control, the preferred equity is not considered to be a component of equity

77
Noble Midstream Partners LP
 
Notes to Consolidated Financial Statements
 


on the consolidated balance sheet, and is reported as mezzanine equity on the consolidated balance sheet. In addition, because the preferred equity was issued by a subsidiary of the Partnership and is held by a third party, it is considered a redeemable noncontrolling interest.
The preferred equity was recorded initially at fair value on the issuance date. Subsequent to issuance, we accrete changes in the redemption value of the preferred equity from the date of issuance to GIP’s earliest redemption date. The preferred equity is perpetual and has a 6.5% annual dividend rate, payable quarterly in cash, with the ability to accrue unpaid dividends during the first two years following the closing. During any quarter in which a dividend is accrued, the accreted value of the preferred equity will be increased by the accrued but unpaid dividend (i.e., a paid-in-kind dividend). See Note 4. Offerings and Acquisition.
Noncontrolling Interests We present our consolidated financial statements with a noncontrolling interest section representing Noble’s retained ownership in the Gunnison River DevCo LP as well as Greenfield Member’s ownership of Black Diamond.
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.
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.
Accounts Receivable and Allowance for Expected Credit Losses  Our accounts receivable result primarily from our midstream gathering services, fresh water services and crude oil sales. The majority of these receivables have payment terms of 30 days or less. At the end of each reporting period, we assess the recoverability of all material receivables using historical data, current market conditions, and reasonable and supportable forecasts of future economic conditions to determine their expected collectibility. The loss given default method is used when, based on management's judgment, an allowance for expected credit losses should be accrued on a material receivable to reflect the net amount expected to be collected. See “Recently Adopted Accounting Standards” below for discussion on our early adoption of Accounting Standards Update No. 2016-13 (ASU 2016-13): Financial Instruments - Credit Losses.
Crude Oil Inventory Our crude oil inventory consists of crude oil that has been purchased. It is stated at the lower of cost or net realizable value. Crude oil inventory is recorded within other current assets in our consolidated balance sheets and totaled $5.6 million and $2.2 million as of December 31, 2019 and 2018, respectively.
Property, Plant and Equipment Property, plant and equipment primarily consists of crude oil gathering systems, natural gas gathering systems, natural gas plants 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 $17.5 million in 2019, $6.4 million in 2018, and $2.5 million in 2017.
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 29 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, changes in customer development plans, and/or increases in our construction or operating costs. In the event that impairment indicators exist, we conduct an impairment test.

78
Noble Midstream Partners LP
 
Notes to Consolidated Financial Statements
 


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 expected 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.
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, 2019.
Intangible Assets Our intangible assets are comprised of customer contracts 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 4. Offerings and Acquisition and Note 7. Intangible Assets.
Goodwill As of December 31, 2019, 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 4. Offerings and 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.
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.

79
Noble Midstream Partners LP
 
Notes to Consolidated Financial Statements
 


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 facilities are variable-rate, non-public debt. The fair value of our revolving credit facility and term loan credit facilities 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 was determined using unobservable inputs and is considered to be a Level 3 measurement on the fair value hierarchy. See Note 7. Intangible Assets.
Certain assets and liabilities, such as property, plant, and equipment, investments, 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.
Transactions with Affiliates Transactions between Noble, its affiliates and us have been identified in the consolidated financial statements as transactions with affiliates. See Note 3. Transactions with Affiliates.
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.
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 $56.6 million and $72.6 million related to midstream capital expenditures as of December 31, 2019 and 2018, respectively.
Greenfield Member contributed approximately $18.8 million of the amount held in escrow at December 31, 2017 for the Black Diamond Acquisition. See the Reconciliation of Total Cash below.
Cash interest paid totaled $33.0 million and $16.3 million for the years ended December 31, 2019 and December 31, 2018, respectively.
In connection with the closing of the Drop-Down and Simplification Transaction, we eliminated a deferred tax asset and current tax liability associated with NBL Holdings. The deferred tax asset and current tax liability totaled approximately $26.0 million and $2.9 million, respectively, and represents a non-cash activity.
Reconciliation of Total Cash We define total cash as cash, cash equivalents and restricted cash. The following table provides a reconciliation of total cash:
 
Year Ended December 31,
(in thousands)
2019
 
2018
 
2017
Cash and Cash Equivalents at Beginning of Period
$
14,761

 
$
20,090

 
$
57,443

Restricted Cash at Beginning of Period (1) (2)
951

 
37,505

 
—

Cash, Cash Equivalents, and Restricted Cash at Beginning of Period
$
15,712

 
$
57,595

 
$
57,443

 
 
 
 
 
 
Cash and Cash Equivalents at End of Period
$
12,676

 
$
14,761

 
$
20,090

Restricted Cash at End of Period (1) (2)
50

 
951

 
37,505

Cash, Cash Equivalents, and Restricted Cash at End of Period
$
12,726

 
$
15,712

 
$
57,595

(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.
Concentration of Credit Risk For the year ended December 31, 2019, revenues from Noble and its affiliates comprised 81% and 59% of our midstream services revenues and total revenues, respectively. There were no individually significant revenues from a third-party in 2019.
For the year ended December 31, 2018, revenues from Noble and its affiliates comprised 81% and 61% of our midstream services revenues and total revenues, respectively. Revenues from a single third-party customer comprised 66% and 17% of our crude oil sales revenues and total revenues, respectively.

80
Noble Midstream Partners LP
 
Notes to Consolidated Financial Statements
 


For the year ended December 31, 2017, revenues from Noble and its affiliates comprised 94% of our midstream services revenues and total revenues. There were no individually significant revenues from a third-party in 2017.
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. 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, processing natural gas, 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, 2019, 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, 2019
2020
$
36,817

2021
37,635

Total
$
74,452


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.
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 Processing Under our natural gas gathering agreements, we receive a fee per million British Thermal Units (“MMBtu”) for the natural gas processing 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.

81
Noble Midstream Partners LP
 
Notes to Consolidated Financial Statements
 


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. 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.
Recently Adopted Accounting Standards
Leases Effective January 1, 2019 we adopted Accounting Standards Update No. 2016-02 (“ASU 2016-02”), which created Topic 842 – Leases (“ASC 842”). The standard requires lessees to recognize a right-of-use (“ROU”) asset and lease liability on the balance sheet for the rights and obligations created by leases. ASC 842 also requires disclosures designed to give financial statement users information on the amount, timing, and uncertainty of cash flows arising from leases.
Upon adoption, we elected the following optional practical expedients:
•
transition ‘practical expedients’, permitting us not to reassess our prior conclusions about lease identification, lease classification and initial direct costs;
•
the practical expedient pertaining to land easements, allowing us to account for existing land easements under previous accounting policy; and
•
the practical expedient to not separate lease and non-lease components for the majority of our leases.
We adopted ASC 842 using the modified retrospective approach. Adoption did not materially impact our consolidated balance sheet or consolidated statement of operations and had no impact on our consolidated statement of cash flows. Our accounting for finance leases remains substantially unchanged.
We determine whether an arrangement contains a lease based on the conveyed rights and obligations at the inception date. If an agreement contains a lease, at the commencement date, we record an ROU asset and a corresponding lease liability based on the present value of lease payments over the lease term. As most of our leases do not provide an implicit rate to determine the present value of lease payments, we use our hypothetical secured borrowing rate based on information available at lease commencement. The weighted average discount rate is 3.69% for operating leases and 2.80% for our finance lease.
Leases with an initial term of 12 months or less are not recorded on the balance sheet and we recognize lease expense for these leases on a straight-line basis over the lease term. Most leases include one or more options to renew, with renewal terms that can extend the lease term from one month to one year or more. Additionally, some of our leases include an option for early termination. We include renewal periods and exclude termination periods from our lease term if, at commencement, it is reasonably likely that we will exercise the option.
Additionally, we have lease agreements that include lease and non-lease components, such as equipment maintenance, which are generally accounted for as a single lease component. Our lease agreements do not contain any material residual value guarantees or material restrictive covenants.
Financial Instruments: Credit Losses In June 2016, the FASB issued Accounting Standards Update No. 2016-13 (“ASU 2016-13”): Financial Instruments – Credit Losses, which replaces the incurred loss impairment methodology with an expected credit loss methodology for financial instruments, including financial assets measured at amortized cost, such as trade and joint interest billing receivables, and off-balance sheet credit exposures not accounted for as insurance, such as financial guarantees and other unfunded loan commitments. The amended standard is effective for fiscal years beginning after December 15, 2019, with early adoption permitted. We early adopted this ASU in fourth quarter 2019. This adoption did not have a material impact on our financial statements.
Recently Issued Accounting Standards
None.

82
Noble Midstream Partners LP
 
Notes to Consolidated Financial Statements
 


Note 3. Transactions with Affiliates
Common Control Transactions
Drop-Down and Simplification Transaction On November 14, 2019, we entered into a Contribution, Conveyance, Assumption and Simplification Agreement with Noble in which we acquired (i) the remaining 60% limited partner interest in Blanco River DevCo LP, (ii) the remaining 75% limited partner interest in Green River DevCo LP, (iii) the remaining 75% limited partner interest in San Juan River DevCo LP and (iv) all of the issued and outstanding limited liability company interests of NBL Holdings, which owns a natural gas processing complex in the DJ Basin and an incremental three-stream gathering system in the Delaware Basin. Additionally, all of Noble’s IDRs were converted into Common Units. The total consideration paid by the Partnership for the Drop-Down and Simplification Transaction was $1.6 billion, which consisted of $670 million in cash and 38,455,018 Common Units issued to Noble. The cash portion of the consideration was funded by the 2019 Private Placement and borrowings under our revolving credit facility. The transaction closed on November 21, 2019. See Note 4. Offerings and Acquisition.
2017 Contribution Agreement On June 20, 2017, we entered into a Contribution Agreement with Noble. Pursuant to the terms of the Contribution Agreement, we acquired (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” and the “2017 Contributed Asset Transaction”). The total consideration paid by the Partnership for the Contributed Assets was $270 million, which consisted of $245 million in cash and 562,430 Common Units issued to Noble. The transaction closed on June 26, 2017.
Revenue and Expense 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)
2019
 
2018
 
2017
Gathering and Processing
$
337,086

 
$
265,505

 
$
189,732

Fresh Water Delivery
77,566

 
69,266

 
75,860

Other
3,183

 
3,976

 
5,677

    Total Midstream Services — Affiliate
$
417,835

 
$
338,747

 
$
271,269


Expenses General and administrative expense consists of the following:
 
Year Ended December 31,
(in thousands)
2019
 
2018
 
2017
General and Administrative Expense — Affiliate
$
8,523

 
$
8,846

 
$
8,677

General and Administrative Expense — Third Party
17,254

 
17,064

 
6,115

    Total General and Administrative Expense
$
25,777

 
$
25,910

 
$
14,792


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 contracted unit of measure 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

83
Noble Midstream Partners LP
 
Notes to Consolidated Financial Statements
 


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 Processing Agreement - Under the natural gas processing agreement, we receive a volumetric fee per MMBtu for the natural gas processing services we provide.
•
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.
Our commercial agreements with Noble include a provision to escalate volumetric fees annually, subject to specific limitations within each agreement. In addition, we can 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.
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 for the provision of certain services by Noble and its affiliates, which fee could not be increased until after the third anniversary of our initial public offering (“IPO”) with annual redetermination thereafter. The cap on the initial rate expired in September 2019 and we have commenced the annual redetermination process;
•
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 interest in Gunnison River DevCo LP; 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.

84
Noble Midstream Partners LP
 
Notes to Consolidated Financial Statements
 


Note 4. Offerings and Acquisition
Offerings
2019 Private Placement On November 14, 2019, the Partnership entered into a Common Unit Purchase Agreement with certain institutional investors, pursuant to which the Partnership agreed to sell 12,077,295 Common Units in a private placement (the “2019 Private Placement”). Gross proceeds totaled approximately $250 million. Net proceeds totaled approximately $242.9 million, after deducting offering expenses of approximately $7.1 million. The 2019 Private Placement closed on November 21, 2019. Proceeds from the 2019 Private Placement were utilized to fund a portion of the cash consideration for the Drop-Down and Simplification Transaction.
Preferred Unit Offering On March 25, 2019, we, through Dos Rios Crude Intermediate LLC, a wholly-owned subsidiary of Dos Rios DevCo LLC, secured a $200 million equity commitment from GIP CAPS Dos Rios Holding Partnership, L.P. (“GIP”), an affiliate of Global Infrastructure Partners Capital Solutions Fund. Upon securing the GIP equity commitment, we issued 100,000 preferred equity units, with a face value of $1,000 per preferred unit. Proceeds from the issuance of the preferred equity totaled $100 million. The preferred equity is perpetual and has a 6.5% annual dividend rate. The remaining $100 million equity commitment is available for a one-year period, subject to certain conditions precedent. The following table provides a reconciliation of our redeemable noncontrolling interest balance:
(in thousands)
Redeemable Noncontrolling Interest
December 31, 2018
$
—

Preferred Equity Issuance
100,000

Issuance Costs
(3,435
)
Preferred Equity Accretion (1)
9,440

December 31, 2019
$
106,005

(1) 
Includes approximately $5.0 million related to dividends that were paid-in-kind. The dividend for each quarter in 2019 was paid-in-kind.
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.
2017 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 “2017 Private Placement”). Net proceeds totaled approximately $138.0 million, after deducting offering expenses of approximately $4.6 million. The closing of the 2017 Private Placement occurred on June 26, 2017.
Acquisition
Black Diamond Acquisition On January 31, 2018, Black Diamond completed the Black Diamond Acquisition for approximately $638.5 million in cash. Black Diamond Gathering Holdings LLC (the “Noble Member ”) and the 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 received a 54.4% equity ownership interest in Black Diamond and Greenfield Member received a 45.6% equity ownership interest in Black Diamond. Noble Member’s agreed equity ownership interest included a 4.4% equity ownership interest promote which was designed to vest only after Noble Member was allocated an amount of gross revenue equal to the contributions by Greenfield Member in excess of its agreed equity ownership interest. As of December 31, 2019, Noble Member has received the necessary allocations of gross revenue and the equity ownership interest promote has vested. See Note 2. Summary of Significant Accounting Policies and Basis of Presentation.

85
Noble Midstream Partners LP
 
Notes to Consolidated Financial Statements
 


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 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.
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.
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 7. 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.
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 a net loss of $11.5 million from Black Diamond were generated from February 1, 2018 to December 31, 2018.

86
Noble Midstream Partners LP
 
Notes to Consolidated Financial Statements
 


The following pro forma consolidated financial information was derived from the historical financial statements of the Partnership and Saddle Butte Rockies Midstream, LLC and certain affiliates 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)
2019 (1)
 
2018
 
2017
Revenues
$
703,801

 
$
569,247

 
$
405,500

Net Income
245,467

 
214,234

 
136,071

Net Income Attributable to Noble Midstream Partners LP
$
159,996

 
$
161,068

 
$
123,375

 
 
 
 
 
 
Net Income Attributable to Limited Partners Per Limited Partner Unit — Basic
 
 
 
 
 
Common Units
$
3.09

 
$
3.92

 
$
3.59

Subordinated Units
$
3.86

 
$
3.92

 
$
3.59

 
 
 
 
 
 
Net Income Attributable to Limited Partners Per Limited Partner Unit — Diluted
 
 
 
 
 
Common Units
$
3.08

 
$
3.92

 
$
3.59

Subordinated Units
$
3.86

 
$
3.92

 
$
3.59

(1) 
No pro forma adjustments were made for the period as Black Diamond operations are included in our results for the full period.
Note 5. Property, Plant and Equipment
Property, plant and equipment, at cost, is as follows:
(in thousands)
December 31, 2019
 
December 31, 2018
Gathering and Processing Systems
$
1,795,957

 
$
1,470,953

Fresh Water Delivery Systems (1)
96,004

 
78,820

Construction-in-Progress (2)
115,034

 
202,349

Total Property, Plant and Equipment, at Cost
2,006,995

 
1,752,122

Accumulated Depreciation and Amortization
(244,038
)
 
(181,199
)
Property, Plant and Equipment, Net
$
1,762,957

 
$
1,570,923

(1) 
Fresh water delivery system assets at December 31, 2019 and December 31, 2018 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, 2019 primarily includes $98.4 million in gathering system projects, $0.3 million in fresh water delivery system projects and $15.4 million in equipment for use in future projects. Construction-in-progress at December 31, 2018 primarily includes $147.4 million in gathering system projects, $21.6 million in fresh water delivery and $32.8 million in equipment for use in future projects.

87
Noble Midstream Partners LP
 
Notes to Consolidated Financial Statements
 


Note 6. Investments
We have ownership interests in the following entities:
•
3.33% interest in White Cliffs;
•
50% interest in Advantage;
•
50% interest in Delaware Crossing;
•
15% interest in EPIC Y-Grade; and
•
30% interest in EPIC Crude.
Advantage On April 3, 2017, we acquired the interest in Advantage for $66.8 million. Advantage owns a crude oil pipeline system in the Southern Delaware Basin.
Delaware Crossing On February 7, 2019, we executed definitive agreements with Salt Creek and completed the formation of Delaware Crossing, which is constructing a crude oil pipeline system in the Delaware Basin. During 2019, we made capital contributions of $70.3 million.
EPIC Y-Grade On January 31, 2019, we exercised and closed our option with E    PIC Midstream Holdings, LP (“EPIC”) to acquire an interest in EPIC Y-Grade, which owns the EPIC Y-Grade pipeline from the Delaware Basin to Corpus Christi, Texas. During 2019, we made capital contributions of $169.1 million.
EPIC Crude On January 31, 2019, we exercised our option with EPIC to acquire an interest in EPIC Crude Holdings, which is constructing the EPIC crude oil pipeline from the Delaware Basin to Corpus Christi, Texas. On March 8, 2019, we closed our option with EPIC to acquire the interest in EPIC Crude. During 2019, we made capital contributions of $351.2 million.
The following table presents our investments at the dates indicated:
(in thousands)
December 31, 2019
 
December 31, 2018
White Cliffs
$
10,268

 
$
9,373

Advantage
76,834

 
72,944

Delaware Crossing
68,707

 
—

EPIC Y-Grade
165,853

 
—

EPIC Crude
339,116

 
—

Total Investments (1)
$
660,778

 
$
82,317

(1) 
We have capitalized $27.9 million in expenses that are included in the basis of the investments. The capitalized items include acquisition related expense and capitalized interest. As of December 31, 2019, $27.7 million remains unamortized.
The following table presents our investment loss (income) for the periods indicated:
 
Year Ended December 31,
(in thousands)
2019
 
2018
 
2017
White Cliffs
$
(3,107
)
 
$
(3,687
)
 
$
(4,088
)
Advantage
(8,159
)
 
(11,880
)
 
(1,779
)
Delaware Crossing
3,061

 
—

 
—

EPIC Y-Grade
8,381

 
—

 
—

EPIC Crude
19,152

 
—

 
—

Other (1)
(1,580
)
 
(722
)
 
(467
)
Total Investment Loss (Income)
$
17,748

 
$
(16,289
)
 
$
(6,334
)

(1) 
Represents our fee for serving as the operator of Advantage and Delaware Crossing.

88
Noble Midstream Partners LP
 
Notes to Consolidated Financial Statements
 


Summarized, 100% combined balance sheet information for equity method investments was as follows:
(in thousands)
December 31, 2019
 
December 31, 2018
Current Assets
$
304,057

 
$
10,451

Noncurrent Assets
4,296,648

 
138,221

Current Liabilities
443,573

 
5,667

Noncurrent Liabilities
$
1,868,138

 
$
288

Summarized, 100% combined statements of operations for equity method investments was as follows:
 
Year Ended December 31,
(in thousands)
2019
 
2018
 
2017
Operating Revenues
$
481,466

 
$
35,153

 
$
11,034

Operating Expenses
575,306

 
11,148

 
7,358

Operating (Loss) Income
(93,840
)
 
24,005

 
3,676

Other Expense (Income)
41,616

 
(37
)
 
—

(Loss) Income Before Income Taxes
(135,456
)
 
24,042

 
3,676

Tax Expense
118

 
171

 
35

Net (Loss) Income
$
(135,574
)
 
$
23,871

 
$
3,641


Subsequent Event In February 2020, Black Diamond exercised its option, effective February 1, 2020, to acquire a 20% ownership interest in Saddlehorn Pipeline Company, LLC (“Saddlehorn”) for $155 million, or $84 million net to the Partnership. The Saddlehorn pipeline transports crude oil and condensate from the DJ Basin and the Powder River Basin to storage facilities in Cushing, Oklahoma, and, after expansion, will have total capacity of 290 MBbl/d.
Saddlehorn is jointly owned by affiliates of Magellan Midstream Partners, L.P. (“Magellan”), Plains All American Pipeline, L.P. (“Plains”) and Western Midstream Partners, LP (“Western Midstream”). After Black Diamond’s purchase, with Magellan and Plains each selling a 10% interest, Magellan and Plains will each own a 30% membership interest and Black Diamond and Western Midstream will each own a 20% membership interest in Saddlehorn. Magellan continues to serve as operator of the Saddlehorn pipeline. The Partnership funded its share of the transaction price with available cash and a draw under its revolving credit facility.

89
Noble Midstream Partners LP
 
Notes to Consolidated Financial Statements
 


Note 7. Intangible Assets
Our intangible assets as of December 31, 2019 are comprised of customer contracts 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, 2019
 
December 31, 2018
(in thousands)
Gross
Accumulated Amortization (1)
Net
 
Gross
Accumulated Amortization (1)
Net
Customer Contracts and Relationships
$
339,760

$
61,860

$
277,900

 
$
339,760

$
29,558

$
310,202

(1) 
For the years ended December 31, 2019 and 2018, amortization expense related to intangible assets totaled $32.3 million and $29.6 million, respectively.
Estimated future amortization expense related to the intangible assets at December 31, 2019 is as follows:
(in thousands)
December 31, 2019
2020
$
32,390

2021
32,301

2022
32,301

2023
32,301

2024
32,390

Thereafter
116,217

Total
$
277,900



90
Noble Midstream Partners LP
 
Notes to Consolidated Financial Statements
 


Note 8. Long-Term Debt
Long-term debt as of December 31, 2019 and December 31, 2018 was as follows:
 
December 31, 2019
 
December 31, 2018
(in thousands, except percentages)
Debt
 
Interest Rate
 
Debt
 
Interest Rate
Revolving Credit Facility, due March 9, 2023
$
595,000

 
3.11
%
 
$
60,000

 
3.67
%
2018 Term Loan Credit Facility, due July 31, 2021
500,000

 
2.85
%
 
500,000

 
3.42
%
2019 Term Loan Credit Facility, due August 23, 2022
400,000

 
2.74
%
 
—

 
—
%
Finance Lease Obligation (1)
2,005

 
—
%
 
3,231

 
—
%
Total
1,497,005

 
 
 
563,231

 
 
Term Loan Credit Facilities Unamortized Debt Issuance Costs
(1,326
)
 
 
 
(979
)
 
 
Total Debt
1,495,679

 
 
 
562,252

 
 
Finance Lease Obligation Due Within One Year (1)
—

 
 
 
(3,231
)
 
 
Long-Term Debt
$
1,495,679

 
 
 
$
559,021

 
 
(1) 
Revolving Credit Facility We maintain a revolving credit facility to fund working capital and to finance acquisitions and expansion capital expenditures. As of December 31, 2018, the borrowing capacity on our revolving credit facility was $800 million. On December 13, 2019, we exercised the accordion feature on our revolving credit facility and increased the capacity to $1.15 billion. We utilized borrowings under the revolving credit facility to fund a portion of the cash consideration paid to Noble in the Drop-Down and Simplification Transaction.
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, 2019 and December 31, 2018, the commitment fee rate was 0.275% and 0.2%, respectively. Unamortized debt issuance costs totaled $3.0 million and $2.7 million as of December 31, 2019 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, 2019. 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 Facilities On August 23, 2019, we entered into a three-year senior unsecured term loan credit facility that permits aggregate borrowings of up to $400 million (the “2019 Term Loan”). Borrowings under the 2019 Term Loan bear interest at a rate equal to, at our option, either (1) a base rate plus an applicable margin between 0.00% and 0.375% per annum or (2) a Eurodollar rate plus an applicable margin between 0.875% and 1.375% per annum.
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 (the “2018 Term Loan”). Borrowings under the 2018 Term Loan 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 facilities contain 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 such covenants as of December 31, 2019. Upon the occurrence and during the continuation of an event of default under the term loan credit facilities, the lenders may declare all amounts outstanding under the term loan credit facilities to be immediately due and payable and exercise other remedies as provided by applicable law.

91
Noble Midstream Partners LP
 
Notes to Consolidated Financial Statements
 


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)
2019
 
2018
Asset Retirement Obligations, Beginning Balance
$
30,533

 
$
23,022

Liabilities Incurred
1,912

 
5,590

Liabilities Settled
(131
)
 
(44
)
Revision of Estimate
3,686

 
646

Accretion Expense (1)
1,842

 
1,319

Asset Retirement Obligations, Ending Balance
$
37,842

 
$
30,533

(1) 
Accretion expense is included in depreciation and amortization expense in the consolidated statements of operations.
Liabilities incurred in 2019 were primarily related to new pipeline installations in the Mustang IDP, Greeley Crescent IDP and Delaware Basin. Revisions of estimates were primarily related to an increase in estimated costs associated with the abandonment of Delaware Basin pipelines and an increase in estimated costs associated with the retirement of our CGFs.
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 associated with the Black Diamond system, 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, 2019 or 2018.
Note 10. Segment Information
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. As a result of our increased investment in midstream entities during first quarter 2019, we have established an Investments in Midstream Entities reportable segment. Our Investments in Midstream Entities reportable segment includes all activity associated with our unconsolidated investments. See Note 6. Investments.
We are now organized into the following reportable segments: Gathering Systems (primarily includes crude oil gathering, natural gas gathering and processing, produced water gathering, and crude oil sales), Fresh Water Delivery, Investments in Midstream Entities and Corporate. We often refer to the services of our Gathering Systems and Fresh Water Delivery reportable segments collectively as our midstream services. Prior period segment information has been reclassified to conform to the current period presentation.

92
Noble Midstream Partners LP
 
Notes to Consolidated Financial Statements
 


Summarized financial information concerning our reportable segments is as follows:
(in thousands)
 
Gathering Systems
 
Fresh Water Delivery
 
Investments in Midstream Entities
 
Corporate (1)
 
Consolidated
Year Ended December 31, 2019
 
 
 
 
 
 
 
 
 
 
Midstream Services — Affiliate
 
$
340,269

 
$
77,566

 
$
—

 
$
—

 
$
417,835

Midstream Services — Third Party
 
83,603

 
12,591

 
—

 
—

 
96,194

Crude Oil Sales — Third Party
 
189,772

 
—

 
—

 
—

 
189,772

Total Revenues
 
613,644

 
90,157

 
—

 
—

 
703,801

Cost of Crude Oil Sales
 
181,390

 
—

 
—

 
—

 
181,390

Direct Operating Expense
 
95,743

 
18,650

 
—

 
2,282

 
116,675

Depreciation and Amortization
 
94,455

 
2,526

 
—

 
—

 
96,981

Income (Loss) Before Income Taxes
 
242,545

 
68,980

 
(17,748
)
 
(44,295
)
 
249,482

Year Ended December 31, 2018
 
 
 
 
 
 
 
 
 
 
Midstream Services — Affiliate
 
$
269,481

 
$
69,266

 
$
—

 
$
—

 
$
338,747

Midstream Services — Third Party
 
59,153

 
19,345

 
—

 
—

 
78,498

Crude Oil Sales — Third Party
 
141,490

 
—

 
—

 
—

 
141,490

Total Revenues
 
470,124

 
88,611

 
—

 
—

 
558,735

Cost of Crude Oil Sales
 
136,368

 
—

 
—

 
—

 
136,368

Direct Operating Expense
 
79,848

 
14,269

 
—

 
1,735

 
95,852

Depreciation and Amortization
 
77,309

 
2,259

 
—

 
—

 
79,568

Income (Loss) Before Income Taxes
 
172,826

 
72,083

 
16,289

 
(36,478
)
 
224,720

Year Ended December 31, 2017
 
 
 
 
 
 
 
 
 
 
Midstream Services — Affiliate
 
$
195,409

 
$
75,860

 
$
—

 
$
—

 
$
271,269

Midstream Services — Third Party
 
7,444

 
10,909

 
—

 
—

 
18,353

Total Midstream Services Revenues
 
202,853

 
86,769

 
—

 
—

 
289,622

Direct Operating Expense
 
50,963

 
16,011

 
—

 
858

 
67,832

Depreciation and Amortization
 
20,724

 
2,266

 
—

 
—

 
22,990

Income (Loss) Before Income Taxes
 
129,770

 
68,492

 
6,344

 
(15,867
)
 
188,739

December 31, 2019
 
 
 
 
 
 
 
 
 
 
Intangible Assets, Net
 
$
277,900

 
$
—

 
$
—

 
$
—

 
$
277,900

Goodwill
 
109,734

 
—

 
—

 
—

 
109,734

Total Assets
 
2,160,026

 
91,840

 
660,778

 
13,438

 
2,926,082

Additions to Long-Lived Assets
 
257,066

 
7,330

 
611,325

 
1,068

 
876,789

December 31, 2018
 
 
 
 
 
 
 
 
 
 
Intangible Assets, Net
 
$
310,202

 
$
—

 
$
—

 
$
—

 
$
310,202

Goodwill
 
109,734

 
—

 
—

 
—

 
109,734

Total Assets
 
1,998,361

 
96,280

 
82,317

 
15,220

 
2,192,178

Additions to Long-Lived Assets
 
738,427

 
23,018

 
426

 
555

 
762,426


(1) 
The Corporate segment includes all general Partnership activity not attributable to our operating subsidiaries.

93
Noble Midstream Partners LP
 
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, 2019, 1,630,638 Common Units are available for future grant under the LTIP.
Restricted unit activity for the year ended December 31, 2019 was as follows:
 
Number of Units
 
Weighted Average Award Date Fair Value
Awarded and Unvested Units at December 31, 2018
71,419

 
$
51.92

Awarded
132,773

 
31.88

Vested
(16,446
)
 
53.45

Forfeited
(84,391
)
 
39.54

Awarded and Unvested Units at December 31, 2019
103,355

 
$
36.04


Unit based compensation expense is recorded within general and administrative expense. For the years ended December 31, 2019, December 31, 2018 and December 31, 2017, our unit based compensation expense was approximately $1.1 million, $1.4 million and $0.8 million, respectively. As of December 31, 2019, $2.1 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 1.5 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 (2)
Holder of IDRs (3)
Total
Q4 2016 (4)
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

Q4 2018
February 4, 2019
February 11, 2019
0.5858

13,876

9,316

2,421

25,613

Q1 2019
May 6, 2019
May 13, 2019
0.6132

14,534

9,751

3,507

27,792

Q2 2019
August 5, 2019
August 12, 2019
0.6418

25,418

—

4,640

30,058

Q3 2019
November 4, 2019
November 12, 2019
0.6716

26,598

—

5,820

32,418

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

94
Noble Midstream Partners LP
 
Notes to Consolidated Financial Statements
 


(2) 
See Conversion of Subordinated Units, below.
(3) 
In November 2019, we acquired all of Noble’s IDRs. See Note 3. Transactions with Affiliates.
(4) 
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.
Conversion of Subordinated Units On April 25, 2019, the board of directors of our General Partner declared a quarterly cash distribution of $0.6132 per unit for the quarter ended March 31, 2019. The distribution was paid on May 13, 2019 to unitholders of record as of the close of business on May 6, 2019. Upon payment of the distribution, the requirements for the conversion of all Subordinated Units were satisfied under our partnership agreement. As a result, on May 14, 2019, all 15,902,584 Subordinated Units, which were owned entirely by Noble, converted into Common Units on a one-for-one basis and thereafter will participate on terms equal with all other Common Units in distributions from available cash.
Cash Distributions On January 23, 2020, the Board of our General Partner declared a quarterly cash distribution of $0.6878 per limited partner unit. The distribution will be paid on February 14, 2020, to unitholders of record on February 4, 2020.
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. For periods prior to the conversion of Subordinated Units and simplification of IDRs, we had more than one class of participating securities and we utilized 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.

95
Noble Midstream Partners LP
 
Notes to Consolidated Financial Statements
 


Our calculation of net income per limited partner Common and Subordinated Unit is as follows:
 
Year Ended December 31,
(in thousands)
2019
 
2018
 
2017
Net Income Attributable to Noble Midstream Partners LP
$
159,996

 
$
162,734

 
$
140,572

Less: Net Income Attributable to Incentive Distribution Rights
13,967

 
5,836

 
835

Net Income Attributable to Limited Partners
$
146,029

 
$
156,898

 
$
139,737

 
 
 
 
 
 
Net Income Allocable to Common Units
$
123,662

 
$
93,875

 
$
75,076

Net Income Allocable to Subordinated Units
22,367

 
63,023

 
64,661

Net Income Attributable to Limited Partners
$
146,029

 
$
156,898

 
$
139,737

 
 
 
 
 
 
Net Income Attributable to Limited Partners Per Limited Partner Unit — Basic
 
 
 
 
 
Common Units
$
3.09

 
$
3.96

 
$
4.10

Subordinated Units
$
3.86

 
$
3.96

 
$
4.10

 
 
 
 
 
 
Net Income Attributable to Limited Partners Per Limited Partner Unit — Diluted
 
 
 
 
 
Common Units
$
3.08

 
$
3.96

 
$
4.10

Subordinated Units
$
3.86

 
$
3.96

 
$
4.10

 
 
 
 
 
 
Weighted Average Limited Partner Units Outstanding — Basic
 
 
 
 
 
Common Units
40,083

 
23,686

 
18,192

Subordinated Units
5,795

 
15,903

 
15,903

 
 
 
 
 
 
Weighted Average Limited Partner Units Outstanding — Diluted
 
 
 
 
 
Common Units
40,105

 
23,701

 
18,204

Subordinated Units
5,795

 
15,903

 
15,903

 
 
 
 
 
 
Antidilutive Restricted Units
54

 
24

 
4


Note 14. Leases
In the normal course of business, we enter into lease agreements to support our operations. We lease field equipment as well as water and pipeline transportation assets.
Operating Leases Our operating leases consist of field equipment and transportation assets. Our field equipment leases have fixed monthly payments over a minimum term with options to extend the rental period on a month-to-month basis. Our leased transportation assets have variable monthly payments (price per barrel throughput) over a minimum term with the option to extend on a year-to-year basis. Our operating and variable lease expense is recorded in direct operating expense in our consolidated statement of operations and was de minimis for the year ended December 31, 2019.
Finance Leases We lease water assets for use in the performance of our fresh water delivery services. The amount of the lease obligation is based on the discounted present value of future minimum lease payments, and therefore does not reflect future cash lease payments. Our finance lease expense is recorded in depreciation and amortization expense in our consolidated statement of operations and was de minimis for the year ended December 31, 2019. Interest expense for our finance lease is recorded in interest expense in our consolidated statement of operations and was de minimis for the year ended December 31, 2019.
Short-Term Leases Leases with an initial term of 12 months or less are not recorded on the balance sheet; we recognize lease expense for these leases on a straight-line basis over the lease term. Short-term lease expense is recorded in direct operating expense in our consolidated statement of operations and was de minimis for the year ended December 31, 2019.

96
Noble Midstream Partners LP
 
Notes to Consolidated Financial Statements
 


Balance Sheet Information ROU assets and lease liabilities are as follows:
(in thousands)
Balance Sheet Location
December 31, 2019
Assets
 
 
Operating (1)
Other Noncurrent Assets
$
2,743

Finance (2)
Total Property, Plant and Equipment, Net
3,869

Total ROU Assets
 
$
6,612

Liabilities
 
 
Current
 
 
Operating
Other Current Liabilities
$
2,471

Finance
Other Current Liabilities
—

Noncurrent
 
 
Operating
Other Noncurrent Liabilities
259

Finance (3)
Long-Term Debt
2,005

Total Lease Liabilities
 
$
4,735

(1) 
All of our operating leases mature between 2020 through 2021. Future operating lease payments of $2.5 million are due in 2020 and $0.3 million are due in 2021.
(2) 
Finance lease assets are recorded net of accumulated amortization of $1.1 million as of December 31, 2019.
(3) 
Our finance lease matures during 2021.
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.
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. The cap on the initial rate expired in September 2019 and we have commenced the annual redetermination process. See Note 3. Transactions with Affiliates.
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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Noble Midstream Partners LP
 
Notes to Consolidated Financial Statements
 


Minimum commitments as of December 31, 2019 are as follows:
(in thousands)
Omnibus
Fee (1)
Future Minimum Finance Lease Payments
Future Minimum Operating Lease Payments
Purchase Obligations (2)
Transportation Fees (3)
Surface Lease Obligations
Total
2020
$
6,850

$
—

$
2,528

$
4,947

$
17,961

$
215

$
32,501

2021
—

2,005

260

—

33,101

216

35,582

2022
—

—

—

—

34,195

175

34,370

2023
—

—

—

—

34,879

175

35,054

2024
—

—

—

—

35,673

175

35,848

2025 and Beyond
—

—

—

—

60,809

3,857

64,666

Total
$
6,850

$
2,005

$
2,788

$
4,947

$
216,618

$
4,813

$
238,021

(1) 
Annual general and administrative fee we pay to Noble for certain administrative and operational support services being provided to us. The initial annual fee can be redetermined during 2020 and may be redetermined annually thereafter. As such, the amount included in the table above represents the annual fee as of December 31, 2019.
(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.
(3) 
We have entered into long-term agreements with unaffiliated third parties to satisfy a substantial portion of our transportation commitment.
Note 16. 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. Taxes are generally borne by our partners through the allocation of taxable income and we do not record deferred taxes related to the aggregate difference in the basis of our assets for financial and tax reporting purposes. We are subject to a Texas margin tax due to our operations in the Delaware Basin and we recorded a de minimis state tax provision for the years ended December 31, 2019, December 31, 2018 and December 31, 2017.
For periods prior to the Drop-Down and Simplification Transaction, our consolidated financial statements include a provision for tax expense on income related to the assets contributed to the Partnership. 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. The following table presents our tax provision for the periods indicated:
 
Year Ended December 31,
(in thousands)
2019
 
2018
 
2017
Current
$
541

 
$
1,323

 
$
1,221

Deferred
3,474

 
6,678

 
26,751

Tax Provision (1)
$
4,015

 
$
8,001

 
$
27,972

Effective Tax Rate
1.6
%
 
3.6
%
 
14.8
%

(1) 
A substantial portion of our tax provision represents federal income taxes associated with the assets contributed in the Drop-Down and Simplification Transaction.
Net deferred tax assets and liabilities were classified in the consolidated balance sheets as follows:
(in thousands)
December 31, 2019
 
December 31, 2018
Deferred Tax Asset (1)
$
—

 
$
29,201

Deferred Tax Liability (2)
229

 
—

(1) 
Our deferred tax asset is recorded within other noncurrent assets in our consolidated balance sheets. See Note 2. Summary of Significant Accounting Policies and Basis of Presentation for a discussion of the elimination of our deferred tax asset and liability prior to the Drop-Down and Simplification Transaction.
(2) 
Our deferred tax liability is recorded within other noncurrent liabilities in our consolidated balance sheets.

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Noble Midstream Partners LP
 
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, 2019
 
 
 
 
 
 
 
 
Total Revenues
 
$
160,702

 
$
170,660

 
$
181,674

 
$
190,765

Operating Income
 
71,987

 
60,564

 
81,271

 
69,644

Income Before Income Taxes
 
69,100

 
56,494

 
71,698

 
52,190

Net Income
 
67,791

 
55,763

 
70,519

 
51,394

Net Income Attributable to Limited Partners
 
40,052

 
31,769

 
34,812

 
39,396

 
 
 
 
 
 
 
 
 
Net Income Attributable to Limited Partners Per Limited Partner Unit — Basic
 
 
 
 
 
 
 


Common Units
 
$
1.01

 
$
0.79

 
$
0.88

 
$
0.65

Subordinated Units
 
1.01

 
0.84

 
—

 
—

Year Ended December 31, 2018
 
 
 
 
 
 
 
 
Total Revenues
 
$
113,225

 
$
139,435

 
$
154,925

 
$
151,150

Operating Income
 
46,346

 
51,985

 
56,779

 
63,768

Income Before Income Taxes
 
48,181

 
54,408

 
57,160

 
64,971

Net Income
 
46,182

 
52,097

 
55,415

 
63,025

Net Income Attributable to Limited Partners
 
38,542

 
35,450

 
43,155

 
39,751

 
 
 
 
 
 
 
 
 
Net Income Attributable to Limited Partners Per Limited Partner Unit — Basic
 
 
 
 
 
 
 
 
Common Units
 
$
0.97

 
$
0.90

 
$
1.09

 
$
1.00

Subordinated Units
 
0.97

 
0.90

 
1.09

 
1.00





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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, 2019. 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 Nasdaq 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 Nasdaq.
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 Nasdaq 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 Nasdaq.
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

101

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 Nasdaq 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, 2019, 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, 2019, our board of directors had ten 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 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.
Name
Age
Position with Our General Partner
Brent J. Smolik
58
Chief Executive Officer and Director
Kenneth M. Fisher
58
Chairman of the Board of Directors
Thomas H. Walker
49
Director
Rachel G. Clingman
53
Director
Hallie A. Vanderhider
62
Director
Martin Salinas, Jr.
47
Director
Andrew E. Viens
65
Director
Thomas W. Christensen
37
Chief Financial Officer
Robin H. Fielder
39
President and Chief Operating Officer
Aaron G. Carlson
53
General Counsel and Secretary
Phillip S. Welborn
31
Chief Accounting Officer
Brent J. Smolik was appointed Chief Executive Officer in August 2019. Mr. Smolik is currently a director of the Partnership and President and Chief Operating Officer of Noble, positions he has held since November 2018. Before joining Noble, Mr. Smolik served as President, Chief Executive Officer and Chairman of the Board of EP Energy Corporation and EP Energy LLC from 2012 to 2017. He previously served as Executive Vice President of El Paso Corporation and President of the El Paso Exploration & Production Company. From 2004 to 2006, Mr. Smolik served as President of ConocoPhillips Canada and Burlington Resources Canada. From 1990 to 2004, he served in a variety of engineering and asset management positions of increasing responsibility for Burlington Resources Inc., including Chief Engineer. He began his career with ARCO Oil and Gas in 1984. Mr. Smolik holds a Bachelor’s Degree in Petroleum Engineering from Texas A&M University. Mr. Smolik previously served on the boards of directors of Cameron International Corporation, America’s Natural Gas Alliance, the Center for Hearing and Speech Foundation,  the Houston Zoo, the Independent Petroleum Association of America and the American Exploration and Production Council. We believe Mr. Smolik’s extensive knowledge of the oil and gas industry and executive leadership experience provides the board of directors of our General Partner with valuable experience and 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 CFO of Shell Oil Products US responsible for US downstream finance operations including Shell Pipeline Company. Prior to joining Shell in 2002, Mr. Fisher held senior finance positions within business units of General Electric Company. Mr. Fisher currently serves on the board of directors of Apergy Corporation as a director and audit committee chairman and formerly served as a director of CONE Midstream Partners from May 2014 to December 2017. We believe Mr. Fisher’s industry and financial experience provides the board of directors of our General Partner with valuable experience in our industry and 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, which he was appointed to in February 2018, and is currently responsible for Noble’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’s operated West Africa assets, non-operated international assets and frontier business ventures and was a member of Noble’s business development team from 2007. Prior to joining Noble in 2007, Mr. Walker held various positions at Amoco and BP America. He currently serves as a member of the LSU Geology & Geophysics Alumni Council. 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.
Rachel G. Clingman was appointed to the board of directors of our General Partner in August 2019. Ms. Clingman is Senior Vice President, General Counsel and Corporate Secretary for Noble. She joined Noble in 2018, bringing more than 25 years of industry experience, most recently as Vice President and General Counsel for the Global Petroleum and Americas Minerals businesses of BHP. Ms. Clingman started her career at a prominent international law firm. She has held various leadership positions within law firms and publicly-traded companies and has served as a registered lobbyist. Ms. Clingman holds

103

Bachelor’s Degrees in Philosophy and Political Science from Rice University, and a Law Degree from the University of Texas where she served on the Texas Law Review. We believe Ms. Clingman’s industry and legal experience provides the board of directors of our General Partner with valuable experience in our strategic, risk and legal matters.
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 since January 2016 and as a director of EQT Corporation and Oil States International, Inc. since July 2019. She previously served as Managing Partner of Catalyst Partners, from May 2013 to June 2018, and as the President and Chief Operating Officer of Black Stone Minerals Company, from October 2007 to May 2013. She joined Black Stone in 2003 and served as 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 and served in a variety of positions at Damson Oil Corp., including as Chief Accounting Officer. In addition, she served on, or is serving on, the following boards: Mississippi Resources, from August 2014 to February 2016; PetroLogistics GP, from April 2013 to July 2014; Bright Horizons, from October 2013 to January 2016; Grey Rock Energy Management, from August 2013 to present; Armor Energy, from May 2016 to present; Frostwood Energy, from May 2016 to present; and Greystone Petroleum, from May 2016 to present. We believe that Ms. Vanderhider’s experience with master limited partnerships, the natural resource industry and financial statements provides the board of directors of our General Partner with valuable experience with respect to our industry and financial matters.
Martin Salinas, Jr. was appointed to the board of directors of our General Partner in October 2016 and is a member of the audit and conflicts committees. Mr. Salinas currently serves as a director of Green Plains Partners, which position he has held since July 2018. He previously served as Chief Executive Officer of Phase 4 Energy Partners from October 2015 to December 2016 and as Chief Financial Officer of Energy Transfer Partners, L.P. from June 2008 through April 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 the Board of Directors from October 2012 to 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’ prior experience as an auditor and chief financial officer provides 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 of 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. Mr. Viens 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, he 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 to 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 Mr. Viens’s extensive marketing and downstream experience provides the board of directors of our General Partner with valuable knowledge and insight.
Thomas W. Christensen was appointed Chief Financial Officer in September 2019 after serving as interim Chief Financial Officer since July 2019. Mr. Christensen has also held the position of Chief Accounting Officer since August 2016. He previously served as Corporate Finance Manager in Noble’s Treasury group and joined Noble upon its acquisition of Rosetta Resources in July 2015. While at Rosetta, Mr. Christensen served in positions of increasing responsibility, including most recently serving as its Assistant Controller overseeing SEC reporting, corporate accounting, income taxes and technical accounting matters. He began his career as an auditor in PricewaterhouseCoopers’ energy practice in Houston. Mr. Christensen is also a certified public accountant.
Robin H. Fielder was appointed President and Chief Operating Officer in January 2020. Ms. Fielder served as President, Chief Executive Officer and Director of the general partners of Western Midstream Operating LP (formerly Western Gas Partners LP) and Western Midstream Partners LP (formerly Western Gas Equity Partners LP) from January 2019 to August 2019, and as President and Director of the general partners from November 2018 to January 2019. She also served as Senior Vice President, Midstream of Anadarko Petroleum Corporation (“Anadarko”) from November 2018 to August 2019. Prior to these positions, Ms. Fielder served in positions of increasing responsibility at Anadarko, including Vice President, Investor Relations from September 2016 to November 2018, Midstream Corporate Planning Manager from December 2015 to September 2016, Director, Investor Relations from June 2014 to December 2015 and General Manager, Carthage/North Louisiana from June 2013 to June 2014. Prior to serving in these roles, she held various exploration and operations engineering positions at

104

Anadarko in both the U.S. onshore and the deepwater Gulf of Mexico. Ms. Fielder holds a Bachelor of Science degree in petroleum engineering from Texas A&M University and is a registered Professional Engineer in the state of Texas and a member of the Society of Petroleum Engineers.
Aaron G. Carlson was appointed General Counsel and Secretary in June 2019. Mr. Carlson joined Noble in April 2003 after spending seven years in private practice. He served in positions of increasing responsibility within Noble’s Legal Department, including Vice President, Deputy General Counsel and Corporate Secretary, before serving in the role of Vice President of Land, Marketing and Production Reporting from May 2018 to July 2019. Mr. Carlson also serves in the position of Vice President of Land for Noble.
Phillip S. Welborn was appointed Chief Accounting Officer in October 2019. He joined Noble in June 2010 and has served in various positions of increasing responsibility within Noble’s accounting department from June 2010 to July 2019. From July 2019 to October 2019, Mr. Welborn served as the Director of Accounting for L. Energy International, LLC. Mr. Welborn is a certified public accountant.
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 2019.

105

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; however, the executive officers of our General Partner are employees of Noble and, as described below, may provide additional services to 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 Noble and our General Partner have not entered into any employment agreements with any of its executive officers, we and our General Partner have entered into the Omnibus Agreement, dated as of September 20, 2016, as amended (the “Omnibus Agreement”), and the Operational Services and Secondment Agreement, dated as of September 20, 2016 (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 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 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 from us for their services to our business or as executive officers of our General Partner.
Named Executive Officers
For 2019, our Named Executive Officers (“Named Executive Officers” or “NEOs”) were:
•
Brent J. Smolik, Chief Executive Officer and Chief Operating Officer;
•
Thomas W. Christensen, Chief Financial Officer and Former Chief Accounting Officer;
•
Aaron G. Carlson, General Counsel and Secretary;
•
Phillip S. Welborn, Chief Accounting Officer;
•
Terry R. Gerhart, Former Chief Executive Officer;
•
John F. Bookout, IV, Former Chief Financial Officer;
•
John C. Nicholson, Former Chief Operating Officer; and
•
Harry R. Beaudry, Former General Counsel and Secretary.
Mr. Smolik was appointed Chief Executive Officer and Chief Operating Officer of our General Partner in August 2019. Mr. Smolik is also an executive officer of Noble, and he devotes a portion of his time to his role at Noble and spends time, as needed, managing our business and affairs. During 2019, Mr. Smolik devoted approximately 25% of his time to managing our business and affairs.
Mr. Christensen was appointed Chief Financial Officer of our General Partner in June 2019. He previously served as Chief Accounting Officer of our General Partner until Mr. Welborn’s appointment to such position. Mr. Christensen devotes substantially all of his time to us and our General Partner.
Mr. Carlson was appointed as General Counsel and Secretary of our General Partner in June 2019. During 2019, Mr. Carlson devoted approximately 50% of his time to managing our business and affairs.
Mr. Welborn was appointed as Chief Accounting Officer of our General Partner in October 2019. Before his appointment as Chief Accounting Officer of our General Partner, Mr. Welborn was previously employed by Noble until he resigned in June 2019, and then was re-hired by Noble to serve as our Chief Accounting Officer. Mr. Welborn devotes substantially all of his time to us and our General Partner.
Mr. Gerhart resigned from his position as Chief Executive Officer of our General Partner effective August 9, 2019. Mr. Gerhart, who was also an executive officer of Noble, devoted a portion of his time to his role at Noble and spent time, as needed, managing our business and affairs. Before his resignation, Mr. Gerhart devoted approximately 60% of his time to managing our business and affairs.
Mr. Bookout resigned from his position as Chief Financial Officer effective June 28, 2019. Before his resignation, Mr. Bookout devoted substantially all of his time to us and our General Partner.
Mr. Nicholson resigned from his position as Chief Operating Officer of our General Partner effective August 9, 2019. Before his resignation, Mr. Nicholson devoted substantially all of his time to us and our General Partner.
Mr. Beaudry resigned from his position as General Counsel and Secretary of our General Partner effective April 5, 2019. Before his resignation, Mr. Beaudry devoted approximately 50% of his time to managing our business and affairs.

106

Elements of Compensation
Noble provides compensation to our executives in the form of base salaries, annual short-term cash incentive awards, long-term equity incentive awards and participation in various employee benefits plans and arrangements. Noble aims to balance at-risk or contingent compensation, provided in the form of annual short-term cash incentive awards and long-term equity incentive awards, with fixed compensation, provided in the form of a base salary. For 2019, a substantial portion of the target compensation of each of our Named Executive Officers was at-risk.
The following discussion sets forth a more detailed explanation of the elements of Noble’s compensation programs as they relate to our Named Executive Officers.
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 executive’s role and responsibilities at Noble, and the executive’s skills, experience, expertise and performance. The table below sets forth the base salary as of December 31, 2019, other than with respect to Messrs. Gerhart, Bookout, Nicholson and Beaudry, for which it provides the base salary of such Named Executive Officers as of their respective resignation dates. The amounts set forth below are pro-rated to reflect the portion of the expense allocated to us by Noble based on the percentage of each Named Executive Officer’s overall working time that was devoted to our business, as described above under “Named Executive Officers.”
Name
Base Salary ($)
Brent J. Smolik
187,500

Thomas W. Christensen
250,000

Aaron G. Carlson
160,850

Phillip S. Welborn
190,000

Terry R. Gerhart
249,000

John F. Bookout, IV
253,960

John C. Nicholson
250,970

Harry R. Beaudry
141,625


We experienced some transition among the individuals serving as our Named Executive Officers in 2019. In connection with these changes in responsibility and title, Noble adjusted base salary to reflect promotions to new positions as follows (prorated to reflect the amount of time allocated to us): Mr. Christensen experienced a 25% salary increase to $250,000 in connection with his promotion to Chief Financial Officer and Mr. Welborn experienced a 53% salary increase to $190,000 in connection with his promotion to Chief Accounting Officer. The base salary for each of Messrs. Smolik and Carlson did not change in connection with their appointments as Chief Executive Officer and as General Counsel and Secretary, respectively. As part of our routine compensation review process, our other Named Executive Officers received the following increases to base salary in 2019 (on a pro-rated basis, to reflect the amount of time allocated to us):
•
for Mr. Gerhart, a 5% increase from $237,000 to $249,000;
•
for Mr. Bookout, a 10% increase from $230,000 to $253,960;
•
for Mr. Nicholson, a 9% increase from $230,000 to $250,970; and
•
for Mr. Beaudry, a 3% increase from $137,500 to $141,625.

107

Short-Term Incentive Plan
Our Named Executive Officers are eligible to receive awards under Noble’s short-term incentive plan (the “STIP”). 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 by Noble and are based on a percentage of the NEO’s base salary. The table below provides the annual bonus targets for the Named Executive Officers for 2019.
Name
Target (as a % of Base Salary)
Brent J. Smolik
110
%
Thomas W. Christensen
35
%
Aaron G. Carlson
45
%
Phillip S. Welborn (1)
30
%
Terry R. Gerhart (2)
65
%
John F. Bookout, IV (2)
35
%
John C. Nicholson (2)
35
%
Harry R. Beaudry (2)
35
%
(1) 
As Mr. Welborn resigned in June 2019 and was re-hired in October 2019, Mr. Welborn’s 2019 STIP award will be pro-rated for the portion of 2019 following his re-hire.
(2) 
As a result of their resignations in 2019, each of Messrs. Gerhart, Bookout, Nicholson and Beaudry were not eligible to receive a payout under the STIP.
The 2019 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 180% of target for the 2019 STIP. For more information regarding the STIP, including a discussion of the performance metrics on which it is based, read Noble’s 2020 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, 2019 (“Noble’s 2020 Proxy Statement”).
2019 STIP Payments
The cash payout under the STIP will occur in March 2020, and the following table shows the final STIP payouts to our Named Executive Officers:
Name
2019 STIP Payout ($)
Brent J. Smolik
408,375

Thomas W. Christensen
174,150

Aaron G. Carlson
138,905

Phillip S. Welborn
17,243

Terry R. Gerhart (1)
—

John F. Bookout, IV (1)
—

John C. Nicholson (1)
—

Harry R. Beaudry (1)
—

(1) As a result of their resignations in 2019, each of Messrs. Gerhart, Bookout, Nicholson and Beaudry were not eligible to receive a payout under the STIP.
Long-Term Equity-Based Compensation Awards
Our Named Executive Officers are eligible to receive awards under the LTIP and under Noble’s long-term equity compensation programs.
Time-Based Restricted Units
The board grants time-based restricted units under our LTIP to provide a retention incentive to the Named Executive Officers and to align the interests of our Named Executive Officers with our unitholders.

108

In February 2019, Messrs. Christensen, Welborn, Gerhart, Bookout, Nicholson and Beaudry received a grant of time-based restricted units under the LTIP. The restricted units will vest, subject to the conditions set forth in the applicable award agreements, as follows:
Vesting Date (1)
Portion of the Restricted Units that Become Vested
February 1, 2020
20%
February 1, 2021
30%
February 1, 2022
50%
(1) 
Messrs. Welborn, Gerhart, Bookout, Nicholson and Beaudry resigned in 2019, and their grants were immediately forfeited and canceled and thus will not vest according to this schedule.
Also during February 2019, Messrs. Christensen, Bookout and Nicholson received a grant of time-based restricted units under the LTIP scheduled to vest in full on the third anniversary of the grant date, which is February 1, 2022. However, Messrs. Bookout and Nicholson resigned in 2019 and their February 2019 grants were immediately forfeited and canceled.
In August 2019, Mr. Christensen received an additional grant of time-based restricted units under the LTIP in connection with his appointment as Chief Financial Officer, which award is scheduled to vest in full on the third anniversary of the grant date. Mr. Christensen’s restricted units will become fully vested, subject to his continued employment and the conditions set forth in the applicable award agreements, on August 5, 2022.
Noble Equity Compensation Awards
Under the Noble Energy, Inc. 1992 Stock Option and Restricted Stock Plan (the “1992 Plan”), as amended from time to time, and subsequently superseded and replaced by the Noble Energy, Inc. 2017 Long-Term Incentive Plan (the “2017 Plan”), as amended from time to time, our Named Executive Officers may receive grants of stock options, restricted stock, phantom units and performance share awards. Equity‑based awards under the 2017 Plan received by our Named Executive Officers in 2019 included time-based restricted shares, time-based phantom units, performance share awards and stock options.
In February 2019, all of our Named Executive Officers received a grant of time-based restricted shares under the 2017 Plan. The time-based restricted shares will vest, subject to the terms set forth in the applicable award agreements, as follows:
Vesting Date (1)
Portion of the Restricted Shares that Become Vested  (2)
February 1, 2020
40%
February 1, 2021
40%
February 1, 2022
20%
(1) 
Mr. Gerhart resigned in 2019 and his grant of time-based restricted shares was immediately forfeited and canceled in connection with his resignation.
(2) 
The above vesting schedule applies to the grant of time-based restricted shares awarded to Messrs. Smolik, Carlson and Gerhart.
Vesting Date (1)
Portion of the Restricted Shares that Become Vested  (2)
February 1, 2020
25%
February 1, 2021
40%
February 1, 2022
35%
(1) 
Messrs. Welborn, Bookout, Nicholson and Beaudry resigned in 2019 and their grants of time-based restricted shares were immediately forfeited and canceled in connection with their respective resignations.
(2) 
The above vesting schedule applies to the grant of time-based restricted shares awarded to Messrs. Christensen, Welborn, Bookout, Nicholson and Beaudry.
In February 2019, Messrs. Smolik, Carlson and Gerhart received a grant of performance-based restricted stock. These performance-based restricted shares vest in full on the third anniversary of the grant date if certain performance metrics are achieved and subject to the executive’s continuous employment through the vesting date. The performance awards granted to Mr. Gerhart in February 2019 were immediately forfeited and canceled on the occurrence of his resignation in August 2019.
In February 2019, all of our Named Executive Officers received a grant of phantom units. Phantom units are the economic equivalent of one share of Noble stock. The phantom units vest in full on the third anniversary of the date of grant and will be settled in cash, subject to the applicable Named Executive Officer’s continued employment through such vesting date. Messrs. Welborn, Gerhart, Bookout, Nicholson and Beaudry resigned in 2019 and their grants of phantom units were immediately forfeited and canceled in connection with their respective resignations.

109

In February 2019, Messrs. Smolik and Gerhart received a grant of stock options under the 2017 Plan. One-third of the stock options become exercisable on each of the first, second, and third anniversaries of the date of grant, subject to the applicable Named Executive Officer’s continued employment through such vesting date. The stock options granted to Mr. Gerhart in February 2019 were immediately forfeited and canceled on the occurrence of his resignation in August 2019.
For more information regarding the awards made pursuant to the equity plans maintained by Noble, read Noble’s 2020 Proxy Statement.
Cash Retention Awards
Noble is focused on retaining the management team to ensure business continuity and continued strong safety, environmental and operational performance. To incentivize continued employment during Noble’s midstream strategic review, on April 25, 2019, Messrs. Christensen, Welborn, Bookout and Nicholson were each awarded a one-time, cash retention award equal to $250,000, $100,000, $500,000 and $500,000, respectively. Noble linked the ability to earn the cash retention awards to each Named Executive Officer’s continued employment through the earlier to occur of (i) a completion of the sale of the Partnership and completion of all related sale transition activities or (ii) April 25, 2022. Each of Messrs. Welborn, Bookout and Nicholson forfeited their ability to earn the cash retention awards upon their respective resignations.
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 2019, 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. 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%
In addition, Messrs. Smolik, Carlson and Gerhart are eligible to participate in the Noble Energy, Inc. 2005 Deferred Compensation Plan (the “Noble 2005 Deferred Compensation Plan”) under which participants may elect to defer portions of their salary and bonus and to receive certain matching, age-weighted and transition contributions that would have been made to Noble’s 401(k) plan, if the 401(k) plan had not been subject to the Internal Revenue Code of 1986, as amended (the “Code”), compensation and contribution limitations.
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 and the 2016 Change of Control Severance Plan for Executives (the “COC Plans”). Mr. Smolik participates in the 2016 Change of Control Severance Plan for Executives and Messrs. Christensen, Carlson and Welborn participate in the 2016 Change of Control Severance Plan. The COC Plans provide 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.
See “Potential Payments Upon Termination or a Change of Control” below for more detail regarding these post-employment compensation arrangements.

110

Other Compensation Items
Tax and Accounting Implications
We account for equity compensation expense in accordance with Financial Accounting Standards Board (“FASB”) Accounting Standard Codification (“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 the later of (i) the date of appointment and (ii) the date of our initial public offering 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 10, 2020, 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, read Noble’s 2020 Proxy Statement.
Actions Taken Following Fiscal-Year End
In January 2020, the board approved awards of restricted units to each of Messrs. Christensen, Carlson and Welborn under the LTIP, which vest one-third on each of the first, second, and third anniversaries of the date of grant.
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 Nasdaq 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:
Brent J. Smolik
 
Kenneth M. Fisher
 
Thomas H. Walker
 
Rachel G. Clingman
 
Hallie A. Vanderhider
 
Martin Salinas, Jr.
 
Andrew E. Viens

111

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, 2019, December 31, 2018, and December 31, 2017. Except as specifically noted, the amounts included in the table 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, as described above under “Compensation Discussion and Analysis—Named Executive Officers” and in the footnotes below.
Name and Principal Position
Year
Salary ($)
Bonus
($)
Stock Awards
($) (7)
Option Awards
($) (8)
Non-Equity Incentive Compensation ($) (9)
All Other Compensation ($) (10)
Total ($)
Brent J. Smolik (Chief Executive Officer and Director) (1)
2019
187,500
—

976,760
153,749
408,375

54,471

1,780,855

Thomas W. Christensen (Chief Financial Officer) (2)
2019
221,366

—

339,698

—

174,150

59,434

794,648

2018
194,070

—

85,374

—

53,485

34,985

367,914

2017
177,424

—

150,259

20,434

65,673

30,019

443,809

Aaron G. Carlson (General Counsel & Secretary) (3)
2019
160,406

—

209,012

—

138,905

43,969

552,292

Philip S. Welborn (Chief Accounting Officer) (2)
2019
105,912

—

37,176

—

17,243

10,591

170,922

Terry R. Gerhart (Former Chief Executive Officer and Director) (4)
2019
188,390

—

864,444

49,499

—

40,375

1,142,708

2018
234,536

—

794,961

45,000

131,421

47,498

1,253,416

2017
—

—

139,984

—

—

5,585

145,569

John F. Bookout, IV (Former Chief Financial Officer) (5)
2019
157,988

—

354,227

—

—

8,014

520,229

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

John C. Nicholson (Former Chief Operating Officer) (5)
2019
185,445

—

354,227

—

—

11,127

550,799

2018
230,000

—

627,963

—

79,407

53,916

991,286

2017
189,423

—

277,613

29,212

112,864

31,836

640,948

Harry R. Beaudry (Former General Counsel & Secretary) (6)
2019
57,873

—

144,708

—

—

3,473

206,054

2018
132,019

—

231,236

—

39,216

27,960

430,431

(1) 
For 2019, Mr. Smolik devoted approximately 25% of his overall working time to our business and the amounts reported are prorated to reflect this.
(2) 
Messrs. Christensen and Welborn devote substantially all of their overall working time to our business. Therefore, the amounts disclosed for 2019 are reported in full, without any proration.
(3) 
For 2019, Mr. Carlson devoted approximately 50% of his overall working time to our business and the amounts reported are prorated to reflect this.
(4) 
For 2019 and 2018, Mr. Gerhart devoted approximately 60% of his overall working time to our business, and the amounts reported for 2019 and 2018, other than with respect to any amount associated with equity awards under our LTIP, 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 received from Noble in relation to the services he provided for us did not comprise a material amount of his total compensation. Mr. Gerhart resigned August 9, 2019. Mr. Gerhart’s 2019 equity awards were forfeited on his resignation date.
(5) 
Messrs. Bookout and Nicholson devoted substantially all of their overall working time to our business. Therefore, the amounts disclosed for 2019 are reported in full, without any proration. Mr. Bookout resigned June 28, 2019 and Mr. Nicholson resigned August 9, 2019. Messrs. Bookout and Nicholson’s 2019 equity awards were forfeited on their resignation dates.
(6) 
For 2019 and 2018, Mr. Beaudry devoted approximately 50% of his overall working time to our business, and the amounts reported for 2019 and 2018, other than with respect to any amount associated with equity awards under our LTIP, are prorated to reflect this. Mr. Beaudry resigned effective April 5, 2019. Mr. Beaudry’s 2019 equity awards were forfeited on his resignation date.
(7) 
The amounts in this column reflect the aggregate grant date fair value of phantom units and restricted stock awarded 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, see Item 8. Financial Statements and Supplementary Data – Note 11. Unit-Based Compensation to our financial statements for the fiscal year ended December 31, 2019 included herein. For more information

112

regarding the restricted stock and phantom units, see Noble’s Form 10-K for the year ended December 31, 2019 (which is not, and shall not be deemed to be, incorporated by reference herein).
(8) 
The amounts in this column reflect 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, see Noble’s Form 10-K for the year ended December 31, 2019 (which is not, and shall not be deemed to be, incorporated by reference herein).
(9) 
Reflects payments under the STIP based on the achievement of certain performance goals during the applicable fiscal year. The STIP awards for 2019 will be paid in March of 2020.
(10) 
All other compensation for 2019 includes the following payments and benefits:
Name
401(k) Matching Contributions ($)
401(k) Retirement Savings Contributions ($)
Deferred Compensation Plan Registrant Contributions ($)(a)
Accrued Dividends ($)
Total All Other Compensation ($)
Brent J. Smolik
4,200

5,050

23,503

21,718

54,471

Thomas W. Christensen
13,282

18,150

—

28,002

59,434

Aaron G. Carlson
8,400

10,100

22,343

3,126

43,969

Phillip S. Welborn
6,355

4,236

—

—

10,591

Terry R. Gerhart
10,080

12,330

17,965

—

40,375

John F. Bookout, IV
8,014

—

—

—

8,014

John C. Nicholson
11,127

—

—

—

11,127

Harry R. Beaudry
3,473

—

—

—

3,473

(a)The following amounts were credited to the following Named Executive Officer’s accounts under the Noble 2005 Deferred Compensation Plan:
 
Year
Matching Contribution ($)
Transition Contribution ($)
Retirement Savings Contribution ($)
Total Deferred Compensation Plan Registrant Contributions ($)
Brent J. Smolik
2019
7,050

—

16,453

23,503

Aaron G. Carlson
2019
8,400

6,788

7,155

22,343

Terry R. Gerhart
2019
10,080

—

7,885

17,965



113

Grants of Plan-Based Awards
The table below sets forth information regarding grants of plan-based awards made to our Named Executive Officers during 2019. 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 2019, as described above under “Compensation Discussion and Analysis—Named Executive Officers.”
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
($/Sh)
Grant
Date
Fair
Value
of Stock
and
Option
Awards
($)(10)
Threshold
($)
Target
($)
Max
($)
Threshold
(#)
Target
(#)
Max
(#)
Brent J. Smolik
1/28/2019
2/1/2019
—
206,250
—
—
—
—
—
 
—
 
—
—
1/28/2019
2/1/2019
—
—
—
11,445
22,890
45,779
—
 
—
 
—
618,017
1/28/2019
2/1/2019
—
—
—
—
—
—
11,445
(4)
—
 
—
256,248
1/28/2019
2/1/2019
—
—
—
—
—
—
4,578
(5)
—
 
—
102,496
1/28/2019
2/1/2019
—
—
—
—
—
—
—
 
20,310
(9)
22.39
153,749
Thomas W. Christensen
1/28/2019
2/1/2019
—
87,500
—
—
—
—
—
 
—
 
—
—
1/28/2019
2/1/2019
—
—
—
—
—
—
1,856
(4)
—
 
—
41,556
1/28/2019
2/1/2019
—
—
—
—
—
—
795
(5)
—
 
—
17,800
1/28/2019
2/1/2019
—
—
—
—
—
—
1,855
(6)
—
 
—
59,360
1/28/2019
2/1/2019
—
—
—
—
—
—
3,781
(7)
—
 
—
120,992
8/2/2019
8/5/2019
—
—
—
—
—
—
3,636
(8)
—
 
—
99,990
Aaron G. Carlson
1/28/2019
2/1/2019
—
72,383
—
—
—
—
—
 
—
 
—
—
1/28/2019
2/1/2019
—
—
—
1,319
2,638
5,275
—
 
—
 
—
71,213
1/28/2019
2/1/2019
—
—
—
—
—
—
4,396
(4)
—
 
—
98,426
1/28/2019
2/1/2019
—
—
—
—
—
—
1,759
(5)
—
 
—
39,373
Philip S. Welborn
1/28/2019
2/1/2019
—
57,000
—
—
—
—
—
 
—
 
—
—
1/28/2019
2/1/2019
—
—
—
—
—
—
581
(4)
—
 
—
13,009
1/28/2019
2/1/2019
—
—
—
—
—
—
249
(5)
—
 
—
5,575
1/28/2019
2/1/2019
—
—
—
—
—
—
581
(6)
—
 
—
18,592
Terry R. Gerhart
1/28/2019
2/1/2019
—
161,850
—
—
—
—
—
 
—
 
—
—
1/28/2019
2/1/2019
—
—
—
3,685
7,369
14,738
—
 
—
 
—
198,968
1/28/2019
2/1/2019
—
—
—
—
—
—
3,685
(4)
—
 
—
82,498
1/28/2019
2/1/2019
—
—
—
—
—
—
1,474
(5)
—
 
—
32,994
1/28/2019
2/1/2019
—
—
—
—
—
—
17,187
(6)
—
 
—
549,984
1/28/2019
2/1/2019
—
—
—
—
—
—
—
 
6,539
(9)
22.39
49,499
John F. Bookout, IV
1/28/2019
2/1/2019
—
88,886
—
—
—
—
—
 
—
 
—
—
1/28/2019
2/1/2019
—
—
—
—
—
—
2,733
(4)
—
 
—
61,192
1/28/2019
2/1/2019
—
—
—
—
—
—
1,171
(5)
—
 
—
26,219
1/28/2019
2/1/2019
—
—
—
—
—
—
2,732
(6)
—
 
—
87,424
1/28/2019
2/1/2019
—
—
—
—
—
—
5,606
(7)
—
 
—
179,392
John C. Nicholson
1/28/2019
2/1/2019
—
87,840
—
—
—
—
—
 
—
 
—
—
1/28/2019
2/1/2019
—
—
—
—
—
—
2,733
(4)
—
 
—
61,192
1/28/2019
2/1/2019
—
—
—
—
—
—
1,171
(5)
—
 
—
26,219
1/28/2019
2/1/2019
—
—
—
—
—
—
2,732
(6)
—
 
—
87,424
1/28/2019
2/1/2019
—
—
—
—
—
—
5,606
(7)
—
 
—
179,392
Harry R. Beaudry
1/28/2019
2/1/2019
—
49,569
—
—
—
—
—
 
—
 
—
—
1/28/2019
2/1/2019
—
—
—
—
—
—
1,508
(4)
—
 
—
33,764
1/28/2019
2/1/2019
—
—
—
—
—
—
646
(5)
—
 
—
14,464
1/28/2019
2/1/2019
—
—
—
—
—
—
3,015
(6)
—
 
—
96,480
(1) 
All grants were approved by our 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 payouts under Noble’s STIP. There are no threshold or maximum amounts under the STIP. Actual payouts under the STIP were determined based on Noble’s achievement against specified performance measures. For more information, see the section entitled “Compensation Discussion and Analysis—Short-Term Incentive Plan” above.
(3) 
The amounts in these columns represent the threshold, target and maximum number of shares that may be issued in settlement of performance awards granted under the 2017 Plan. The performance awards will vest February 1, 2022 if the specified performance goals are satisfied, subject to the applicable Named Executive Officer’s continued employment through such vesting date. These performance shares held by Mr. Gerhart were forfeited in connection with his resignation in 2019.

114

(4) 
Represents the shares of restricted stock awarded under the 2017 Plan. The restricted shares will vest according to the following schedule: 40% on the first and second anniversaries of the date of grant and 20% on the third anniversary of the date of grant. Dividends declared on shares of restricted stock are accrued during the three-year restricted period and will be paid upon vesting of restricted shares. The restricted shares held by Messrs. Welborn, Gerhart, Bookout, Nicholson and Beaudry were forfeited in connection with their resignations in 2019.
(5) 
Represents phantom units awarded under the 2017 Plan. Phantom units are the economic equivalent of one share of Noble stock. The award will vest 100% on the third anniversary date of the grant and will settle in cash, subject to the applicable Named Executive Officer’s continued employment through such vesting date. Dividends declared on shares underlying the phantom units are accrued during the three-year restricted period and will be paid upon vesting of the phantom units. These phantom units held by Messrs. Welborn, Gerhart, Bookout, Nicholson and Beaudry were forfeited in connection with their resignations in 2019.
(6) 
These grants of restricted units under our LTIP became vested as to 20% on February 1, 2020 and will become vested as to 30% on February 1, 2021 and 50% on February 1, 2022, subject to the applicable Named Executive Officer’s continued employment through each vesting date. These restricted units held by Messrs. Welborn, Gerhart, Bookout, Nicholson and Beaudry were forfeited in connection with their resignations in 2019.
(7) 
These grants of restricted units under our LTIP will become vested on February 1, 2022, subject to the applicable Named Executive Officer’s continued employment through such vesting date. These restricted units held by Messrs. Bookout and Nicholson were forfeited in connection with their resignations in 2019.
(8) 
These grants of restricted units under our LTIP will become vested on August 5, 2022, subject to Mr. Christensen’s continued employment through such vesting date.
(9) 
These non-qualified 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, 2020 and will become exercisable as to 1/3 of the shares on each of February 1, 2021, and February 1, 2022, subject to the applicable Named Executive Officer’s continued employment through each vesting date. These options held by Mr. Gerhart were forfeited in connection with his resignation in 2019.
(10) 
Reflects the aggregate grant date fair value of (i) phantom units, restricted stock and non-qualified stock options granted under Noble’s 2017 Plan and (ii) restricted units granted under our LTIP, in each case computed in accordance with FASB ASC Topic 718. For more information regarding the restricted units granted under our LTIP, see Item 8. Financial Statements and Supplementary Data – Note 11. Unit-Based Compensation to our financial statements for the fiscal year ended December 31, 2019. For more information regarding the phantom units, restricted stock and stock options granted under the 2017 Plan, see Noble’s Form 10-K for the year ended December 31, 2019 (which is not, and shall not be deemed to be, incorporated by reference herein).
Outstanding Equity Awards at Fiscal Year-End
The table below sets forth information regarding stock options, restricted stock, performance share awards, phantom units and restricted units held by our Named Executive Officers as of December 31, 2019. 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 2019, as described above under “Compensation Discussion and Analysis—Named Executive Officers.”

115

 
Option Awards (1)
Stock Awards
Name
Number of Securities Underlying Unexercised Options (#) Exercisable
Number of Securities Underlying Unexercised Options (#) Unexercisable
Option Exercise Price ($)
Option Expiration Date
Number of Shares or Units of Stock Held That Have Not Vested (#)
Market Value of Shares or Units of Stock Held That Have Not Vested ($)(20)
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 ($)(20)
Brent J. Smolik
9,758

19,516

(2)
25.17

 11/16/2028

34,764

(5)
863,525

45,779

(18)
1,137,150

—

20,310

(3)
22.39

2/1/2029

11,445

(6)
284,288

—

 
—

—

—

 
—

 
4,578

(7)
113,711

—

 
—

Thomas W. Christensen
1,775

—

 
31.65

2/1/2026

259

(8)
6,434

—

 
—

1,027

514

(4)
39.46

2/1/2027

464

(9)
12,324

—

 
—

—

—

 
—

—

1,940

(10)
51,526

—

 
—

—

—

 
—

—

1,106

(11)
27,473

—

 
—

—

—

 
—

—

602

(12)
15,989

—

 
—

—

—

 
—

—

1,856

(6)
46,103

—

 
—

—

—

 
—

—

3,781

(13)
100,423

—

 
—

—

—

 
—

—

1,855

(14)
49,269

—

 
—

—

—

 
—

—

3,636

(15)
96,572

—

 
—

—

—

 
—

—

795

(7)
19,748

—

 
—

Aaron G. Carlson
1,977

—

 
37.55

2/1/2020

887

(8)
22,021

5,867

 (19)
145,736

1,980

—

 
45.20

2/1/2021

1,369

(17)
34,006

5,275

 (18)
131,031

2,479

—

 
50.91

 2/1/2022

4,396

(6)
109,197

—

 
—

3,158

—

 
54.60

 2/1/2023

1,759

(8)
43,694

—

 
—

1,711

—

 
62.33

1/31/2024

—

 
—

—

 
—

2,464

—

 
47.74

1/30/2025

—

 
—

—

 
—

2,363

—

 
31.65

 2/1/2026

—

 
—

—

 
—

1,172

587

(4)
39.46

2/1/2027

—

 
—

—

 
—

866

1,731

(16)
30.89

2/1/2028

—

 
—

—

 
—

Phillip S. Welborn
446

—

 
54.60

7/3/2020

—

 
—

—

 
—

292

—

 
62.33

7/3/2020

—

 
—

—

 
—

323

—

 
47.74

7/3/2020

—

 
—

—

 
—

587

—

 
31.65

7/3/2020

—

 
—

—

 
—

251

—

 
39.46

 7/3/2020

—

 
—

—

 
—

Terry R. Gerhart
9,396

—

 
37.55

2/1/2020

—

 
—

—

 
—

7,548

—

 
45.20

2/1/2021

—

 
—

—

 
—

9,724

—

 
50.91

2/1/2022

—

 
—

—

 
—

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

 8/9/2024

—

 
—

—

 
—

13,168

—

 
31.65

 8/9/2024

—

 
—

—

 
—

7,038

—

 
39.46

 8/9/2024

—

 
—

—

 
—

1,432

—

 
30.89

8/9/2024

—

 
—

—

 
—

John F. Bookout, IV
936

—

 
47.74

6/28/2020

—

 
—

—

 
—

1,065

—

 
31.65

6/28/2020

—

 
—

—

 
—

1,028

—

 
39.46

6/28/2020

—

 
—

—

 
—

John C. Nicholson
305

—

 
50.91

8/9/2020

—

 
—

—

 
—

226

—

 
50.91

8/9/2020

—

 
—

—

 
—

886

—

 
54.60

8/9/2020

—

 
—

—

 
—

1,205

—

 
62.33

8/9/2020

—

 
—

—

 
—

1,619

—

 
47.74

8/9/2020

—

 
—

—

 
—

733

—

 
31.65

8/9/2020

—

 
—

—

 
—

1,468

—

 
39.46

8/9/2020

—

 
—

—

 
—

Harry R. Beaudry
1,008

—

 
32.85

4/5/2020

—

 
—

—

 
—

(1) 
The option awards in these columns are options to purchase shares of Noble stock granted under the 1992 Plan or 2017 Plan.
(2) 
50% of stock options vest November 16, 2020 and 50% of stock options vest November 16, 2021, subject to the applicable Named Executive Officer’s continued employment through the vesting date.
(3) 
33 1/3% of stock options vested February 1, 2020; 33 1/3% of stock options vest February 1, 2021; and 33 1/3% of stock options vest February 1, 2022, subject to the applicable Named Executive Officer’s continued employment through the vesting date.
(4) 
These options became exercisable on February 1, 2020.

116

(5) 
100% of these restricted shares of Noble granted under the 2017 Plan will vest on November 16, 2021, subject to the applicable Named Executive Officer’s continued employment through the vesting date.
(6) 
40% of these restricted shares of Noble granted under the 2017 Plan vested February 1, 2020; 40% of these restricted shares will vest on February 1, 2021; and the remainder will vest on February 1, 2022, subject to the applicable Named Executive Officer’s continued employment through the vesting date.
(7) 
100% of these phantom units granted under the 2017 Plan will vest on February 1, 2022 and will be settled in cash, subject to the applicable Named Executive Officer’s continued employment through the vesting date.
(8) 
These restricted shares of Noble stock vested on February 1, 2020.
(9) 
These restricted units granted under our LTIP vested on February 1, 2020.
(10) 
100% of these restricted units granted under our LTIP will vest on May 4, 2020, subject to the applicable Named Executive Officer's continued employment through the vesting date.
(11) 
37% of these restricted shares of Noble granted under the 2017 Plan vested February 1, 2020 and the remainder will vest on February 1, 2021, subject to the applicable Named Executive Officer's continued employment through the vesting date.
(12) 
37% of these restricted units granted under our LTIP vested February 1, 2020 and the remainder will vest on February 1, 2021, subject to the applicable Named Executive Officer’s continued employment through the vesting date.
(13) 
100% of these restricted units granted under our LTIP will vest on February 1, 2022, subject to the applicable Named Executive Officer’s continued employment through the vesting date.
(14) 
20% of these restricted units granted under our LTIP vested February 1, 2020; 30% of these restricted units will vest on February 1, 2021; and the remainder will vest on February 1, 2022, subject to the applicable Named Executive Officer’s continued employment through the vesting date.
(15) 
100% of these restricted units granted under our LTIP will vest on August 5, 2022, subject to the applicable Named Executive Officer’s continued employment through the vesting date.
(16) 
50% of these options became exercisable on February 1, 2020 and the remaining 50% will become exercisable on February 1, 2021, subject to the applicable Named Executive Officer’s continued employment through such vesting date.
(17) 
50% of these restricted shares of Noble granted under the 2017 Plan vested February 1, 2020 and the remainder will vest on February 1, 2021, subject to the applicable Named Executive Officer’s continued employment through the vesting date.
(18) 
These shares of performance-based Noble restricted stock granted under the 2017 Plan will vest on February 1, 2022, subject to achievement of total stockholder return levels relative to a pre-determined industry peer group. Because performance as of December 31, 2019 was trending at maximum, these shares reflect the number of shares that would be earned based on maximum achievement of the applicable performance metrics. The actual number of shares that vest at the end of the performance period may differ substantially from the number of shares reported herein.
(19) 
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. Because performance as of December 31, 2019 was trending at target, these shares reflect the number of shares that would be earned based on maximum achievement of the applicable performance metrics. The actual number of shares that vest at the end of the performance period may differ substantially from the number of shares reported herein.
(20) 
Amounts reported in these columns are calculated based on $26.56, the closing price of our common units on December 31, 2019, or $24.84, the closing price of Noble stock on December 31, 2019, as applicable.


117

Option Exercises and Stock Vested
The table below sets forth information regarding the vesting of restricted stock and restricted unit awards during fiscal year 2019. No stock options were exercised by the Named Executive Officers during fiscal year 2019. Except for restricted units under our LTIP that vested during 2019, 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 2019, as described above under “Compensation Discussion and Analysis—Named Executive Officers.”
 
Stock Awards
Unit Awards
Name
Number of Shares Acquired on Vesting (#)
Value Realized on Vesting ($)(4)
Number of Shares Acquired on Vesting (#)
Value Realized on Vesting ($)(5)
Brent J. Smolik
—

 
—

—

 
—

Thomas W. Christensen
432

(1)
9,672

429

(2)
13,728

Aaron G. Carlson
2,433

(1)
54,475

—

 
—

Phillip S. Welborn
141

(1)
3,157

124

(2)
3,968

Terry R. Gerhart
3,304

(1)
73,977

2,715

(2)
86,880

John F. Bookout, IV
693

(1)
15,516

571

(2)
18,272

John C. Nicholson
765

(1)
17,128

694

(2)
22,208

Harry R. Beaudry
1,966

(3)
46,084

—

 
—

(1) 
These amounts represent restricted stock awards granted on February 1, 2017 and February 1, 2018 under the 2017 Plan, which vested on February 1, 2019.
(2) 
These amounts represent restricted unit awards granted on February 1, 2017 and February 1, 2018 under our LTIP, which vested on February 1, 2019.
(3) 
This amount represents restricted stock awards granted on March 27, 2017 and February 1, 2018 under the 2017 Plan, which vested on February 1, 2019 and March 27, 2019, respectively.
(4) 
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 2019 as follows: Mr. Christensen - $248; Mr. Carlson - $1,472; Mr. Welborn- $76; Mr. Gerhart - $1,987; Mr. Bookout - $360; Mr. Nicholson - $418 and Mr. Beaudry - $1,220.
(5) 
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 restricted units that vested were paid in 2019 as follows: Mr. Christensen - $1,388; Mr. Welborn - $379; Mr. Gerhart - $7,360; Mr. Bookout - $1,686; and Mr. Nicholson - $2,152.
Pension Benefits
Our Named Executive Officers do not participate in a defined benefit pension plan.
Nonqualified Deferred Compensation
The following table sets forth certain information with respect to contributions made to the Noble 2005 Deferred Compensation Plan by our Named Executive Officers during fiscal year 2019. The amounts set forth in the table below reflect an allocation based on the percentage of each Named Executive Officer’s overall working time that was devoted to our business during 2019, as described above under “Compensation Discussion and Analysis-Named Executive Officers.”
Name
Executive Contributions in Last Fiscal Year ($) (1)
Noble Contributions in Last Fiscal Year ($)
 
Aggregate Earnings in Last Fiscal Year ($) (4)
Aggregate Withdrawals/Distributions in Last Fiscal Year ($)
Aggregate Balance at Last Fiscal Yearend ($) (5)
Brent J. Smolik
7,500

23,503

(2)
660

—
31,663

Aaron G. Carlson
—

13,943

(3)
38,948

—
221,666

Terry R. Gerhart
1,889

7,885

(2)
45,648

—
1,366,094

(1)   Mr. Smolik deferred 4% ($7,500) of base salary in 2019. Mr. Gerhart deferred 1% ($1,889) of base salary in 2019.
(2) Represents matching contributions and retirement savings contributions that could not be made to Noble's 401(k) Plan as a result of Code limitations.
(3)   Represents retirement savings contributions that could not be made to Noble's 401(k) Plan as a result of Code limitations.
(4)   Earnings are credited in accordance with the Named Executive Officer's investment direction.
(5)   All Named Executive Officers are 100% vested in these balances, except for Mr. Smolik who will be vested on November 16, 2021.

118


Noble's matching contributions, retirement savings contributions and transition contributions credited to the Noble 2005 Deferred Compensation Plan accounts of our Named Executive Officers are reflected in the “All Other Compensation” column of the Summary Compensation Table above.
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 to 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 designated 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.
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 by 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.

119

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 Code.
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 and phantom units 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 and phantom units will immediately vest. If a Named Executive Officer’s employment is terminated for any other reason, all shares of restricted stock and phantom units 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 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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Noble 2005 Deferred Compensation Plan
Under the Noble 2005 Deferred Compensation Plan, if a Named Executive Officer is unvested in any portion of Noble’s contributions, such unvested amounts will accelerate upon such Named Executive Officer’s death, disability or involuntary termination or upon a change in control.
As used in the 2005 Deferred Compensation 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.
•
“Permanent Disability” means the total and permanent incapacity of a Participant to perform the usual duties of his or her employment with an Employer or Affiliated Company as determined by the Committee. Such incapacity shall be deemed to exist when certified by a physician acceptable to the Committee.
•
“Good reason” generally means a (a) material reduction in base compensation or bonus, (b) material change in the location of employment, or (c) material reduction in employee benefits or material increase in employee benefit costs.
•
“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 or after the participant attains age 65.


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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, 2019.
Name
Type of Payment or Benefit
Death ($)
Disability ($)
Termination Without Cause
($) (9)
Termination without Cause following a Change of Control of NBLX ($)
Termination without Cause or Resignation for Good Reason following a Change of Control of Noble ($)
Brent J. Smolik
Cash Severance
—

—

998,077

—

4,025,100

STIP Payments (1)
825,000

—

—

—

825,000

NBLX Restricted Units (2)
—

—

—

—

—

Noble Restricted Stock (3)
4,678,122

4,678,122

463,451

—

4,678,122

Noble Restricted Stock Units (4)
463,451

463,451

—

—

463,451

Noble Performance Share Award (5)
2,317,333

2,317,333

—

—

4,634,667

Noble Stock Options (6)
199,040

199,040

66,346

—

199,040

Continued Medical Benefits (7)
—

—

8,294

—

41,469

Life Insurance (8)
1,000,000

—

—

—

—

Retirement Benefits
94,013

94,013

94,013

—

94,013

Total
9,576,959

7,751,959

1,630,181

—

14,960,862

Thomas W. Christensen
Cash Severance
—

—

145,192

—

240,385

STIP Payments (1)
87,500

—

—

—

87,500

NBLX Restricted Units (2)
362,267

362,267

96,103

362,267

362,267

Noble Restricted Stock (3)
82,214

82,214

29,196

—

82,214

Noble Restricted Stock Units (4)
20,122

20,122

—

—

20,122

Noble Performance Share Award (5)
—

—

—

—

—

Noble Stock Options (6)
—

—

—

—

—

Continued Medical Benefits (7)
—

—

11,388

—

11,388

Life Insurance (8)
500,000

—

—

—

—

Retention Bonus (10)
—

—

—

250,000

—

Total
1,052,103

464,603

281,879

612,267

803,876

Aaron G. Carlson
Cash Severance
—

—

351,395

—

482,550

STIP Payments (1)
144,765

—

—

—

144,765

NBLX Restricted Units (2)
—

—

—

—

—

Noble Restricted Stock (3)
339,347

339,347

170,574

—

339,347

Noble Restricted Stock Units (4)
89,015

89,015

—

—

89,015

Noble Performance Share Award (5)
284,526

284,526

—

—

415,557

Noble Stock Options (6)
—

—

—

—

—

Continued Medical Benefits (7)
—

—

13,029

—

13,029

Life Insurance (8)
644,000

—

—

—

—

Total
1,501,653

712,888

534,998

—

1,484,263

Phillip S. Welborn
Cash Severance
—

—

124,962

—

138,846

STIP Payments (1)
57,000

—

—

—

57,000

NBLX Restricted Units (2)
—

—

—

—

—

Noble Restricted Stock (3)
—

—

—

—

—

Noble Restricted Stock Units (4)
—

—

—

—

—

Noble Performance Share Award (5)
—

—

—

—

—

Noble Stock Options (6)
—

—

—

—

—

Continued Medical Benefits (7)
—

—

11,388

—

11,388

Life Insurance (8)
380,000

—

—

—

—

Total
437,000

—

136,350

—

207,234

(1) 
Named Executive Officers would not be entitled to a STIP payment for 2019 in the event of their termination of employment on December 31, 2019, other than in the event of a change of control or death.
(2) 
Amounts reported in this row are calculated based on $26.56, the closing price of our Common Units on December 31, 2019 and includes accrued distributions.
(3) 
Amounts reported in this row are calculated based on $24.84, the closing price of Noble stock on December 31, 2019 and includes accrued dividends. All unvested shares of time-based restricted stock, including accrued dividends, will vest in the event of termination of employment as a result of a change of control, death or disability.
(4) 
Amounts reported in this row are calculated based on the difference between the applicable stock options for which exercisability would be accelerated and $24.84, the closing price of Noble stock on December 31, 2019. All unvested shares of time-based restricted stock units payable in cash, including accrued dividends, will vest in the event of termination of employment as a result of a change of control, death or disability.
(5) 
Amounts reported in this row are calculated based on $24.84, the closing price of Noble stock on December 31, 2019 and includes accrued dividends. All unvested performance share awards, including accrued dividends, will vest at target in the event of termination

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of employment as a result of death or disability. In the event of a termination of employment as a result of a change of control, all unvested performance share awards, including accrued dividends, will vest based on the actual performance of the award where the performance period ends on the last day of the full calendar month ending on or immediately preceding the date of the termination of employment.
(6) 
Amounts reported in this row are calculated based on the difference between the applicable stock options for which exercisability would be accelerated and $24.84, the closing price of Noble stock on December 31, 2019. Because the exercise price of the Noble stock options held by Messrs. Christensen and Carlson each exceeded $24.84, no value is associated with the acceleration of exercisability of these options.
(7) 
Amounts reported in this row reflect the estimated cost to Noble of providing continued medical, dental and vision benefits.
(8) 
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.
(9) 
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.  In addition any unvested equity awards, including accrued dividends, that would vest within twelve months of the termination of employment will vest due to the involuntary termination. They would also be able to continue certain health and welfare benefits for six months at the current active employee rates.
(10) 
Mr. Christensen is a party to a cash retention award that vests upon the sale of the Partnership, so long as Mr. Christensen (i) remains employed through the date of such sale or was previously terminated without cause, (ii) satisfactorily performs his duties through the date of such sale and (iii) completes all related sale transition activities. See “Compensation Discussion and Analysis—Elements of Compensation—Cash Retention Awards” above, for a complete description of the cash retention award.

Resignations During Fiscal Year 2019
As described under “Compensation Discussion and Analysis—Named Executive Officers,” Messrs. Gerhart, Bookout, Nicholson and Beaudry resigned effective August 9, 2019, June 28, 2019, August 9, 2019 and April 5, 2019, respectively. In connection with their respective resignations, all unvested equity awards were forfeited. Additionally, all outstanding and exercisable stock options in Noble held by Messrs. Bookout, Nicholson and Beaudry will expire on the first anniversary of their respective resignation dates. All outstanding and exercisable stock options in Noble held by Mr. Gerhart will expire on the earliest to occur of (i) the expiration date of the stock option or (ii) the fifth anniversary of his resignation date, as his resignation was considered a Retirement under the 1992 Plan and 2017 Plan.
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.

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The following table provides information regarding the compensation earned by our non-employee directors during the year ended December 31, 2019.
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 granted under our LTIP, computed in accordance with FASB ASC Topic 718. For more information, see Item 8. Financial Statements and Supplementary Data – Note 11. Unit-Based Compensation to our financial statements for the fiscal year ended December 31, 2019. As of December 31, 2019, each of Ms. Vanderhider and Messrs. Salinas and Viens held 3,750 unvested restricted units, which vested on February 1, 2020.
CEO Pay Ratio
As required by Section 953(b) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 402(u) of Regulation S-K, we are providing the following information about the relationship of the annual total compensation of Brent J. Smolik, our Chief Executive Officer, to the median annual total compensation of other employees providing services to us. As described in Items 1. and 2. Business and Properties - Employees, 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 and omnibus agreement that we entered into with Noble. Because the employees required to conduct and support our operations are employed by Noble, we are unable to calculate and provide a ratio of the median employee’s annual total compensation to the total annual compensation of Mr. Smolik.

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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 5, 2020, the beneficial ownership of Common 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.
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
 
Noble Energy, Inc.
1001 Noble Energy Way
Houston, Texas 77070
 
56,447,616

 
62.6
%
(1) 
(1) 
Based upon its Schedule 13D/A filed with the SEC on November 22, 2019, with respect to its beneficial ownership of our Common Units, Noble Energy has sole voting and dispositive power with respect to 56,447,616 units.
Directors/Named Executive Officers
Total Common Units Beneficially Owned (1)
Percent of Total Outstanding
Rachel G. Clingman
—

*
Kenneth M. Fisher
15,500

*
Martin Salinas, Jr.
24,881

*
Hallie A. Vanderhider
17,881

*
Andrew E. Viens
17,348

*
Thomas Hodge Walker
500

*
Brent J. Smolik (2)
7,500

*
Thomas W. Christensen
19,071

*
Aaron G. Carlson
4,488

*
Phillip S. Welborn
2,651

*
Terry R. Gerhart (3)
17,419

*
John F. Bookout, IV (4)
7,531

*
John C. Nicholson (3)
3,373

*
Harry R. Beaudry (3)
—

*
All Directors and Executive Officers as a Group (14 persons)
138,143

*
*
Less than 1%.
(1) 
None of the Common Units reported in this column are pledged as security.
(2) 
Includes 2,500 units held by trust.
(3) 
Values for the Common Units from the exit Form 4 filed upon Messrs. Gerhart, Nicholson and Beaudry's resignations.
(4) 
Values for the Common Units from Company records upon Mr. Bookout's resignation.

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The following table sets forth, as of February 5, 2020, 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 5, 2020 and the shares underlying deferred stock units and the shares underlying restricted stock units that will be settled within 60 days of February 5, 2020. 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
Rachel G. Clingman
93,431

*
Kenneth M. Fisher
637,972

*
Martin Salinas, Jr.
—

*
Hallie A. Vanderhider
—

*
Andrew E. Viens
—

*
Thomas Hodge Walker
127,518

*
Brent J. Smolik
303,280

*
Thomas W. Christensen
10,753

*
Aaron G. Carlson
62,249

*
Phillip S. Welborn
3,450

*
Terry R. Gerhart (1)
114,153

*
John F. Bookout, IV (2)
4,397

*
John C. Nicholson (2)
8,763

*
Harry R. Beaudry (2)
3,921

*
All Directors and Executive Officers as a Group (14 persons)
1,369,887

*
*
Less than 1%.
(1) Value for the restricted shares from the exit Form 4 filed upon Mr. Gerhart's resignation; stock option information from Company records.
(2) Value for the restricted shares and stock option information from Company records.

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Item 13.  Certain Relationships and Related Transactions, and Director Independence
Noble owns 56,447,616 Common Units which represented a 62.6% limited partner interest in us. In addition, our General Partner owns a non-economic General Partner interest in us.
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. These distributions and payments were determined by and among affiliated entities and, consequently, are not the result of arm’s-length negotiations.
Distributions of available cash to Noble:
•
We will generally make cash distributions to our unitholders pro rata, including Noble, as holder of an aggregate 56,447,616 Common Units.
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.
Upon our liquidation, the partners, including our General Partner, will be entitled to receive liquidating distributions according to their respective capital account balances.
Agreements with our Affiliates
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. 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
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, for the provision of certain services by Noble and its affiliates. The cap on the initial rate expired in September 2019 and we have commenced the annual redetermination process.
•
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 interest in Gunnison River DevCo LP; 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

127

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), 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 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 was not to 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. The cap on the initial rate expired on September 2019 and we have commenced the annual redetermination process.
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.
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, 2019, granted to us by Noble.
Areas Served
NBLX ROFR Service
Current Status of Asset
ROFR Net Acreage
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
37,000
Delaware Basin
Natural Gas Gathering
Fresh Water Services
In Progress
92,000
Powder River and Green River Basins
Crude Oil Gathering
Natural Gas Gathering
Natural Gas Processing
Water Services
N/A
181,000
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 interest in Gunnison River DevCo LP. Pursuant to our ROFO, before Noble can offer its retained interest in Gunnison River DevCo to any third party, Noble must allow us to make an offer to purchase the interest. We are under no obligation to purchase Noble’s retained interest, and Noble is only under an obligation to permit us to make an offer on the interest to the extent that Noble elects to sell these midstream assets to a third party.
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

128

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);
•
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.

129

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.
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, 2018 and December 31, 2019 for professional services performed by our independent registered public accounting firm KPMG LLP:
 
Year Ended December 31,
(in thousands)
2019
 
2018
Audit Fees (1)
$
1,823

 
$
1,350

Audit-Related Fees
—

 
—

Tax Fees
—

 
—

All Other Fees
—

 
—

Total Fees
$
1,823

 
$
1,350

(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, 2019, 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, 2020.

130

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.

131

Index to Exhibits

Exhibit Number
 
Exhibit
 
 
 
2.1
 
 
 
 
2.2+
 

 
 
 
3.1
 
 
 
 
3.2
 
 
 
 
3.3
 
 
 
 
3.4
 
 
 
 
3.5
 
 
 
 
3.6
 
 
 
 
3.7
 
 
 
 
3.8
 
 
 
 
4.1
 
 
 
 
4.2
 
 
 
 
4.3
 
 
 
 
10.1
 
 
 
 

132


10.2*
 
 
 
 
10.3
 
 
 
 
10.3.1
 
 
 
 
10.3.2
 
 
 
 
10.3.3
 
 
 
 
10.4
 
 
 
 
10.5
 
 
 
 
10.5.1
 
 
 
 
10.5.2
 
 
 
 
10.5.3
 
 
 
 
10.5.4
 
 
 
 
10.6
 
 
 
 

133


10.6.1†
 
 
 
 
10.6.1.1
 
 
 
 
10.6.2†
 
 
 
 
10.6.2.1
 
 
 
 
10.6.2.2†
 
 
 
 
10.6.3
 
 
 
 
10.6.4
 
 
 
 
10.7
 
 
 
 
10.7.1†
 
 
 
 
10.7.2†
 
 
 
 
10.8
 
 
 
 
10.8.1†
 
 
 
 
10.8.1.1
 
 
 
 

134


10.8.2†
 
 
 
 
10.8.2.1
 
 
 
 
10.8.3
 
 
 
 
10.8.3.1
 
 
 
 
10.8.3.2†
 
 
 
 
10.8.4
 
 
 
 
10.8.4.1
 
 
 
 
10.8.5
 
 
 
 
10.8.5.1
 
 
 
 
10.8.6
 
 
 
 
10.8.9
 
 
 
 
10.9
 
 
 
 

135


10.9.1†
 
 
 
 
10.9.2
 
 
 
 
10.10
 
 
 
 
10.10.1†
 
 
 
 
10.10.1.1
 
 
 
 
10.10.1.2†
 
 
 
 
10.10.2†
 
 
 
 
10.10.2.1
 
 
 
 
10.10.3†
 
 
 
 
10.10.3.1
 
 
 
 
10.10.3.2†
 
 
 
 
10.10.4
 
 
 
 
10.10.4.1
 
 
 
 

136


10.10.5
 
 
 
 
10.10.5.1
 
 
 
 
10.10.6
 
 
 
 
10.10.7
 
 
 
 
10.11
 
 
 
 
10.11.1†
 
 
 
 
10.11.1.1
 
 
 
 
10.11.2†
 
 
 
 
10.11.2.1
 
 
 
 
10.11.3
 
 
 
 
10.11.3.1
 
 
 
 
10.11.3.2†
 
 
 
 
10.11.4
 
 
 
 

137


10.11.4.1
 
 
 
 
10.11.5
 
 
 
 
10.11.5.1
 
 
 
 
10.11.6
 
 
 
 
10.11.7
 
 
 
 
10.12
 
 
 
 
10.12.1†
 
 
 
 
10.12.2
 
 
 
 
10.13
 
 
 
 
10.13.1
 
 
 
 
10.14
 
 
 
 
10.14.1
 
 
 
 
10.15
 
 
 
 
10.16
 
 
 
 
10.16.1
 
 
 
 
10.17
 
 
 
 
10.17.1
 
 
 
 

138


10.18
 
 
 
 
10.19*
 
 
 
 
10.20*
 
 
 
 
10.20.1*
 
 
 
 
10.21*
 
 
 
 
10.21.1*
 
 
 
 
10.22
 
 
 
 
10.23
 
 
 
 
10.24
 
 
 
 
10.25
 
 
 
 
10.26
 
 
 
 
10.27
 
 
 
 
21.1
 
 
 
 
23.1
 
 
 
 
31.1
 
 
 
 
31.2
 
 
 
 
32.1
 
 
 
 
32.2
 
 
 
 

139


101
 
The following materials from Noble Midstream Partners LP's Annual Report on Form 10-K for the year ended December 31, 2019 formatted in iXBRL (Inline eXtensible Business Reporting Language): (i) Consolidated Statements of Operations and Comprehensive Income; (ii) Consolidated Balance Sheets; (iii) Consolidated Statements of Cash Flows; (iv) Consolidated Statements of Changes in Equity; and (v) Notes to Consolidated Financial Statements.
 
 
 
104
 
Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).
* Management contract or compensatory plan or arrangement required to be filed as an exhibit hereto.
† 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.
+ 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.
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


140

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 12, 2020
By: /s/ Brent J. Smolik
 
 
Brent J. Smolik,
 
 
Chief Executive Officer and Director
 
 
 
Date:
February 12, 2020
By: /s/ Thomas W. Christensen
 
 
Thomas W. Christensen,
 
 
Chief Financial Officer
 
 
 
Date:
February 12, 2020
By: /s/ Phillip S. Welborn
 
 
Phillip S. Welborn,
 
 
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/ Brent J. Smolik
 
Chief Executive Officer and Director
 
February 12, 2020
Brent J. Smolik
 
(Principal Executive Officer)

 
 
 
 
 
 
 
/s/ Thomas W. Christensen
 
Chief Financial Officer
 
February 12, 2020
Thomas W. Christensen
 
(Principal Financial Officer)
 
 
 
 
 
 
 
/s/ Phillip S. Welborn
 
Chief Accounting Officer
 
February 12, 2020
Phillip S. Welborn
 
(Principal Accounting Officer)
 
 
 
 
 
 
 
/s/ Kenneth M. Fisher
 
Chairman of the Board of Directors
 
February 12, 2020
Kenneth M. Fisher
 
 
 
 
 
 
 
 
 
/s/ Thomas H. Walker
 
Director
 
February 12, 2020
Thomas H. Walker
 
 
 
 
 
 
 
 
 
/s/ Rachel G. Clingman
 
Director
 
February 12, 2020
Rachel G. Clingman
 
 
 
 
 
 
 
 
 
/s/ Hallie A. Vanderhider
 
Director
 
February 12, 2020
Hallie A. Vanderhider
 
 
 
 
 
 
 
 
 
/s/ Martin Salinas, Jr.
 
Director
 
February 12, 2020
Martin Salinas, Jr.
 
 
 
 
 
 
 
 
 
/s/ Andrew E. Viens
 
Director
 
February 12, 2020
Andrew E. Viens
 
 
 
 

141
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