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Table of Contents
Index to Financial Statements
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, 2020
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
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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 classTrading Symbol(s)Name of each exchange on which registered
Common Units, Representing Limited Partner InterestsNBLXThe 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 has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C.7262(b)) by the registered public accounting firm that prepared or issued its audit report.
 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, 2020, the last business day of the registrant’s most recently completed second fiscal quarter was approximately $285.2 million.
The registrant had 90,347,145 Common Units as of January 29, 2021.
DOCUMENTS INCORPORATED BY REFERENCE: None


Table of Contents
Index to Financial Statements
Table of Contents
 
PART I
Items 1. and 2.
Item 1A.
Item 1B.
Item 3.
Item 4.
PART II
Item 5.
Item 6.
Item 7.
Item 7A.
Item 8.
Item 9.
Item 9A.
Item 9B.
PART III
Item 10.
Item 11.
Item 12.
Item 13.
Item 14.
PART IV
Item 15.
Item 16.




Table of Contents
Index to Financial Statements
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. In addition, our forward-looking statements address the various risks and uncertainties associated with the extraordinary market environment and impacts resulting from the COVID-19 pandemic and the actions of foreign oil producers (most notably Saudi Arabia and Russia) to maintain market share and impact commodity pricing and the expected impact on our business, results of operations and earnings.
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 our 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. 
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.
As used in this report, such terms as “Noble Midstream Partners,” “NBLX,” “the Partnership,” “us,” “our,” “we” or similar expressions may refer to Noble Midstream Partners LP, one or more of its consolidated subsidiaries, or all of them taken as a whole, but unless stated otherwise they do not include “affiliates” of Noble Midstream Partners. All of these terms are used for convenience only and are not intended as a precise description of any of the separate companies, each of which manages its own affairs.
For a summary of commonly used industry terms and abbreviations used in this report, see the Glossary.
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PART I

Items 1. and 2. Business and Properties
Overview
Chevron Merger
On July 20, 2020, Noble Energy, Inc. (“Noble”) entered into a definitive merger agreement (the “Chevron Merger Agreement”) with Chevron Corporation. On October 5, 2020, Chevron Corporation completed the acquisition of Noble, the indirect general partner and majority unitholder of the Partnership, through the merger of Chelsea Merger Sub Inc., a direct, wholly owned subsidiary of Chevron Corporation, with and into Noble, with Noble surviving and continuing as a direct, wholly owned subsidiary of Chevron Corporation (the “Chevron Merger”). As a result, Chevron Corporation (i) indirectly, wholly owns our general partner, Noble Midstream GP LLC (our “General Partner”), and (ii) indirectly holds approximately 62.6% of our limited partner common units (“Common Units”). Throughout this filing and depending upon the context, we make references to Chevron1 as Chevron indirectly, wholly owns our General Partner and make references to Noble as our historical agreements with Noble remain intact subsequent to the Chevron Merger.
Non-Binding Proposal from Chevron
On February 4, 2021, the board of directors of General Partner received a non-binding proposal from Chevron Corporation, pursuant to which Chevron would acquire all common units of the Partnership that Chevron and its affiliates do not already own in exchange for a to-be-determined fixed exchange ratio, based on a value of $12.47 per common unit. If approved, the transaction would be effected through a merger of the Partnership with a subsidiary of Chevron.
The transaction, as proposed, is subject to a number of contingencies, including the approval of the conflicts committee, the approval by holders of a majority of the outstanding common units of the Partnership and the satisfaction of any conditions to the consummation of a transaction set forth in any definitive agreement concerning the transaction. There can be no assurance that definitive documentation will be executed or that any transaction will materialize.
Our Operations
We are a growth-oriented Delaware master limited partnership formed in December 2014 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 current areas of operation are in the Denver-Julesburg Basin in Colorado (“DJ Basin”) and the Southern Delaware Basin position of the Permian Basin (“Delaware Basin”) in Texas.

1 As used in this report, the term “Chevron” may refer to Chevron Corporation, one or more of its consolidated subsidiaries, or all of them taken as a whole, but unless stated otherwise, they do not include “affiliates” of Chevron. All of these terms are used for convenience only and are not intended as a precise description of any of the separate companies, each of which manages its own affairs.
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The map below illustrates our areas of operation:
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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.
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 this relationship. While our relationship with Noble is a significant strength, it is also a source of potential risks and conflicts as it 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. 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.

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Organizational Structure
The following diagram depicts our organizational structure as of December 31, 2020.
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(1)Effective with the completion of the acquisition of Noble by Chevron Corporation, Chevron Corporation indirectly owns our General Partner and Noble.
(2)We have an unconsolidated ownership interest in the entity. See Item 8. Financial Statements and Supplementary Information - Note 2. Summary of Significant Accounting Policies and Basis of Presentation and Item 8. Financial Statements and Supplementary Information – Note 6. Investments.

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The following table provides a summary of our development areas within each basin, along with our dedicated services and customers as of December 31, 2020.
CompanyAreas ServedNBLX Dedicated ServiceCustomers
Colorado River LLC
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 LLCEast Pony IDP (DJ Basin)Water ServicesNoble
Green River DevCo LLC Mustang IDP (DJ Basin)Crude Oil Gathering
Natural Gas Gathering
Water Services
Noble
Laramie River LLC 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
Crude Oil Transmission
Noble and Unaffiliated Third Parties
Gunnison River DevCo LP
Bronco IDP (DJ Basin) (1)
Crude Oil Gathering
Water Services
Noble
Blanco River LLC Delaware Basin Crude Oil Gathering
Natural Gas Gathering
Water Services
Noble and Unaffiliated Third Parties
Trinity River DevCo LLCDelaware BasinNatural Gas Compression
Crude Oil Transmission
Noble and Unaffiliated Third Parties (2)
Dos Rios DevCo LLCDelaware BasinCrude Oil Transmission
Y-Grade Transmission
Fractionation
Noble and Unaffiliated Third Parties (2)
Noble Midstream Holdings LLCEast Pony IDP (DJ Basin)Natural Gas Gathering
Natural Gas Processing
Noble and Unaffiliated Third Parties
Delaware BasinCrude Oil Gathering
Natural Gas Gathering
Water Services
Noble and Unaffiliated Third Parties
(1)While we currently have no midstream infrastructure assets in the Bronco IDP, we have dedications for Noble’s future production from this area.
(2)The unaffiliated third-party customers are served through our investments in midstream entities in which we exert significant influence.
2020 Developments
Commodity Prices and COVID-19
The impacts on our business of both the significant decline in commodity prices and the COVID-19 pandemic are unprecedented. During 2020, we continued to focus on providing midstream solutions for our customer base and maintaining safe and reliable operations. Against this backdrop, we continued to expand our strategic relationships and investments in the long-haul pipeline business, as discussed further below. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Executive Overview for further discussion on the impact of the decline in commodity prices and COVID-19 on our results of operations, liquidity and cash flows.
Investment Activity
In February 2020, our affiliate, Black Diamond Gathering LLC (“Black Diamond”) exercised and closed an option to acquire a 20% ownership interest in Saddlehorn Pipeline Company, LLC (“Saddlehorn”) for $160 million, $87 million net to the Partnership with Greenfield Midstream, LLC (“Greenfield Member”) contributing the remaining $73 million for its portion. Black Diamond purchased a 10% interest from each of Magellan Midstream Partners, L.P. (“Magellan”) and Plains All American Pipeline, L.P. (“Plains”). Magellan continues to serve as operator of the Saddlehorn Pipeline, which is 30% owned by each of Magellan and Plains and 20% owned by each of Black Diamond and Western Midstream Partners, LP.
Additionally, in 2020, we continued to contribute to our 50% interest in Delaware Crossing LLC (“Delaware Crossing”), 30% interest in EPIC Crude Holdings, LP (“EPIC Crude”), 15% interest in EPIC Y-Grade, LP (“EPIC Y-Grade”), and 15% interest in EPIC Propane Pipeline Holdings, LP (“EPIC Propane”).
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Index to Financial Statements
Operations
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 Holdings, L.L.C. (“Advantage”), Delaware Crossing, EPIC Crude, EPIC Y-Grade, EPIC Propane, Saddlehorn 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
DJ Basin
Our crude oil gathering system in the Wells Ranch IDP area consists of shared crude oil and produced water gathering pipelines as well as the Wells Ranch CGF that has total crude oil throughput capacity of 50 MBbl/d and storage capacity of 96,000 Bbls. At the Wells Ranch CGF we are able to recover gas vapors from crude oil and deliver this natural gas for delivery to downstream third parties. In January 2021, we began to provide crude oil transmission services from the Wells Ranch IDP area to Platteville, Colorado, through our recent capacity arrangement on the Wattenberg Oil Trunkline (“WOT”). This new arrangement will provide for long-haul transportation out of the DJ Basin.
In the East Pony IDP area, we gather crude oil meeting pipeline specifications and deliver it directly into the northern extension of WOT and the Northeast Colorado Lateral of the Pony Express Pipeline. Our gathering system in the East Pony IDP area has total crude oil throughput capacity of 85 MBbl/d. 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 area, we gather crude oil meeting pipeline specifications and deliver it into the Black Diamond Milton Terminal. Our gathering system in the Mustang IDP area has total crude oil throughput capacity of 60 MBbl/d.
To service the Greeley Crescent IDP area, we gather crude oil meeting pipeline specifications for an unaffiliated third party. We can deliver the gathered crude oil to the Grand Mesa Pipeline and to the White Cliffs pipeline system (the “White Cliffs Pipeline”) via the Black Diamond Lucerne and Milton terminals. Our gathering system in the Greeley Crescent IDP area has total crude oil throughput capacity of 60 MBbl/d.
To service the Black Diamond dedication area, we gather crude oil meeting pipeline specifications and deliver it to various delivery points. The gathering system in the Black Diamond dedication area has total crude oil throughput capacity of approximately 330 MBbl/d. 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.
Delaware Basin
Our crude oil gathering systems in the Delaware Basin consist of pipelines that gather off-spec crude oil from well pad facilities, which is delivered to various CGFs. We have five operational CGFs in the Delaware Basin that have total crude oil throughput capacity of 96MBbl/d. The CGFs stabilize the crude oil to meet pipeline specifications and deliver to downstream pipelines leaving the Delaware Basin.
Additionally, we have a crude oil gathering system that has total crude oil throughput capacity of 12 MBbl/d. The system services production from certain 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.
Year Ended December 31,
Average Daily Throughput (Bbl/d)20202019
DJ Basin174,644 182,121 
Delaware Basin54,347 49,842 

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Natural Gas Gathering
DJ Basin
Our natural gas infrastructure assets in the Wells Ranch IDP area consist of the Wells Ranch CGF and a natural gas pipeline system that 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 area. The Wells Ranch CGF has total natural gas throughput capacity of 175 MMcf/d. 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 area consists of a natural gas pipeline system that has total throughput capacity of 250 MMcf/d. The 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 area. The natural gas is then processed by third parties.
Our natural gas infrastructure in the East Pony IDP area consists of a natural gas pipeline system that collects natural gas from the wellhead and delivers it to our Lilli and Keota gas processing plants or other third-party processing facilities. For further discussion of the Lili and Keota gas processing plants, see the Natural Gas Processing discussion below.
Delaware Basin
Our natural gas infrastructure assets in the Delaware Basin consist of five CGFs as well as a 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. Our CGFs have total natural gas throughput capacity of 184 MMcf/d.
Additionally, we have a natural gas pipeline system with a total natural gas throughput capacity of 23 MMcf/d that services production from certain acreage in the Delaware Basin. The 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.
Year Ended December 31,
Average Daily Throughput (MMBtu/d) (1)
20202019
DJ Basin503,794 476,605 
Delaware Basin166,032 155,155 
(1)The natural gas throughput capacity information discussed above is in cubic feet. To convert cubic feet to British thermal units, multiply cubic feet by 1.3.
Natural Gas Processing
All of our natural gas processing infrastructure resides in the East Pony IDP area of the DJ Basin. Our infrastructure 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.
Year Ended December 31,
Average Daily Throughput (MMBtu/d) (1)
20202019
DJ Basin41,511 50,039 
(1)The natural gas processing capacity information discussed above is in cubic feet. To convert cubic feet to British thermal units, multiply cubic feet by 1.3.
Produced Water Gathering
DJ Basin
Our produced water gathering system in the Wells Ranch IDP area 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 a gathering pipeline system (which is a shared crude oil and produced water gathering
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pipeline) servicing the Wells Ranch IDP area. At the Wells Ranch CGF, the incoming crude oil and produced water liquid stream is separated, stored, and treated before the produced water is delivered to a third-party pipeline for disposal. The Wells Ranch CGF has total produced water throughput capacity of 30 MBbl/d.
Our produced water gathering system in the Mustang IDP area gathers liquids produced from operations and consists of a combination of pumps and permanent pipelines to transport produced water to third-party disposal facilities. Our gathering system in the Mustang IDP area has total produced water throughput capacity of 30 MBbl/d.
Our produced water gathering system in the Greeley Crescent IDP area gathers liquids produced from operations and consists of a combination of pumps and permanent pipelines to transport produced water to third-party disposal facilities. Our gathering system in the Greeley Crescent IDP area has total produced water throughput capacity of 20 MBbl/d.
Delaware Basin
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. At our CGFs, the incoming produced water is skimmed and pumped downstream to disposal wells. Our CGFs have total throughput capacity of 240 MBbl/d.
Additionally, we have a produced water gathering system servicing production from certain acreage in the Delaware Basin. This system has total throughput capacity of 20 MBbl/d and transports produced water 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.
Year Ended December 31,
Average Daily Throughput (Bbl/d)20202019
DJ Basin35,190 39,629 
Delaware Basin138,449 148,886 
Fresh Water Delivery
Our fresh water services are in the DJ Basin and include distribution and storage services that are integral to our customers’ drilling and completion operations. Our fresh water systems includes a fresh water distribution system comprised of buried pipelines in the East Pony IDP, Wells Ranch IDP, Mustang IDP, and Greeley Crescent IDP areas. In addition, our fresh water systems include fresh water storage facilities in the Wells Ranch IDP, East Pony IDP, and Mustang IDP areas, 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 segregate 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.
Year Ended December 31,
Average Daily Throughput (Bbl/d)20202019
DJ Basin91,886 164,524 
Investments in Midstream Entities
Our Investments in Midstream Entities reportable segment includes our investments in White Cliffs, Advantage, Delaware Crossing, EPIC Crude, EPIC Y-Grade, EPIC Propane and Saddlehorn.
White Cliffs
We own a 3% 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.
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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 completed construction of a 95-mile pipeline system that originates in Pecos County, Texas, and has additional connections in Reeves County and Winkler County, Texas. The crude oil pipeline system began delivering crude oil into all connection points in second quarter 2020. The project footprint is 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.
EPIC Crude
In second quarter 2020, EPIC Crude commenced operations on an approximately 700-mile pipeline, with a capacity of 600 MBbl/d, from the Delaware Basin to the Gulf Coast.
EPIC Y-Grade
In second quarter 2020, EPIC Y-Grade commenced operations on its 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 has a throughput capacity of approximately 440 MBbl/d with multiple origin points.
EPIC Propane
EPIC Propane is constructing a propane pipeline that will run from the EPIC Y-Grade Logistics, LP fractionator complex in Robstown, Texas to the Phillips 66 petrochemical facility in Sweeney, Texas, with additional connectivity to the Markham underground storage caverns.
Saddlehorn
We own a 20% interest in Saddlehorn. Prior to its expansion, the Saddlehorn Pipeline was 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. During first quarter 2021, the pipeline expanded by 100 MBbl/d, to a new total capacity of 290 MBbl/d.
Corporate
Our Corporate segment includes all general Partnership activity and expenses not attributable to our operating subsidiaries. This primarily includes 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. For more information, see Item 1A. Risk Factors, particularly our risk factor entitled “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.”
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
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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. 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. Additionally, as part of the Consolidated Appropriations Act of 2021, Congress reauthorized PHMSA through 2023 and directed the agency to move forward with several regulatory actions, including the “Pipeline Safety: Class Location Change Requirements” and the “Pipeline Safety: Safety of Gas Transmission and Gathering Pipelines” proposed rulemakings. Congress has also instructed PHMSA to issue final regulations that will require operators of non-rural gas gathering lines and new and existing transmission and distribution pipeline facilities to conduct certain leak detection and repair programs and to require facility inspection and maintenance plans to align with those regulations. 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 thus, 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.
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 $1,307,164 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.
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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. On December 17, 2020, in Docket No. RP20-14-000, the FERC issued an order establishing a new index level of PPI plus 0.78% for the five-year period commencing July 1, 2021. This order is subject to rehearing and several rehearing requests were filed.
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. Currently, therefore, 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 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.
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.
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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 manner in which we are permitted to 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 emissions 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. The regulation of methane from oil and gas facilities has been subject to uncertainty in recent years. In September 2020, the U.S. Administration revised prior regulations to rescind certain methane standards and remove the transmission and storage segments from the source category for certain regulations. However, on January 20, 2021, an executive order was signed calling for the suspension, revision, or rescission of the September 2020 rule and the reinstatement or issuance of methane emissions standards for new, modified, and existing oil and gas facilities.
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. For example, in December 2019, the EPA reclassified the Denver area to Serious nonattainment for ozone. As a result, the State of Colorado was obligated to revise its State Implementation Plan (SIP) in order to attain the ozone standard, including the adoption of new categories of controls on emissions sources and applying a lower threshold for permitting large sources. Under the revised SIP, a source that emits or has the potential to emit 50 tons per year or more of nitrogen oxides or 50 tons per year or more of volatile organic compounds is a major stationary source and is therefore subject to the more onerous Title V operating permit program. Certain of our Colorado facilities were impacted by the lower threshold and became subject to the Title V permit applicability. The impacts of any additional or more complex initiatives cannot be predicted, and one or more of them may negatively impact the supply or demand for oil and gas products and, therefore, our services, or could result in new regulatory requirements that affect our operations or our cost of doing business.
At the international level, the United Nations-sponsored “Paris Agreement” requires member states to individually determine and submit non-binding emissions reduction targets every five years after 2020. Although the United States had previously withdrawn from the Paris Agreement, an executive order was signed on January 20, 2021 recommitting the United States to the agreement. The impacts of this order, and any legislation or regulation that may be adopted as a result, are unclear at this time.
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However, 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.
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. There is also a risk that financial institutions will be required to adopt policies that have the effect of reducing the funding provided to the fossil fuel sector. A material reduction in the capital available to the fossil fuel industry could make it more difficult to secure funding for exploration, development, production, transportation, and processing activities, which could result in decreased demand for our midstream services. 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 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. In September 2019, the EPA and Corps rescinded the 2015 Clean Water Rule and, in January 2020, published a revised definition. Legal challenges have occurred for each of these rulemakings, and it
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is possible that the new presidential administration could propose a broader interpretation of the CWA’s jurisdiction. 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. Separately, in April 2020, the federal district court for the District of Montana determined that the Corps Clean Water Act Section 404 Nationwide Permit 12 (“NWP 12”) failed to comply with consultation requirements under the federal Endangered Species Act. The district court vacated NWP 12 and enjoined the issuance of new authorizations for oil and gas pipeline projects. While the district court’s order has subsequently been limited pending appeal and NWP 12 authorizations remain available for certain oil and gas pipeline projects, we cannot predict the ultimate outcome of this case and its impacts to the Nationwide Permit program. Relatedly, in response to the vacatur, the Corps has reissued the NWP 12 for oil and natural gas pipeline activities, including certain revisions to the conditions for the use of NWP 12; however, the rule may be subject to further revisions or suspension under the current U.S. Administration. While the full extent and impact of the vacatur is unclear at this time, any disruption in our ability to obtain coverage under NWP 12 or other general permits may result in increased costs and project delays if we are forced to seek individual permits from the Corps.
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.
Hydraulic Fracturing
We do not conduct hydraulic fracturing operations, but substantially all of Noble’s crude oil and natural gas production on our dedicated acreage is developed from unconventional sources, such as shale, that require hydraulic fracturing as part of the completion process. The majority of our fresh water services business is related to the storage and transportation of water for use in hydraulic fracturing. Hydraulic fracturing is a well stimulation process that utilizes large volumes of water and sand combined with fracturing chemical additives that are pumped into a well at high pressure to crack open previously impenetrable rock to release hydrocarbons. Hydraulic fracturing is typically regulated by state oil and gas commissions and similar agencies. Some states and local governments, including those in which we operate, have adopted, and other states are considering adopting, regulations that could impose more stringent chemical disclosure or well construction requirements on hydraulic fracturing operations, or otherwise seek to ban some or all of these activities. For example, in Colorado, state ballot and other regulatory initiatives have been proposed from time to time to impose additional restrictions or bans on hydraulic fracturing or other facets of crude oil and natural gas exploration, production or related activities. 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 regulations requiring green completions for hydraulically fractured wells, and emission requirements for certain midstream equipment. Also, in June 2016, the EPA finalized rules that prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants. Separately, on January 20, 2021, the Department of the Interior has temporarily suspended the issuance of new authorizations for oil and gas developments on federal lands, although the order does not apply to existing operations under valid leases. Certain environmental groups have also suggested that additional laws may be needed to more closely and uniformly regulate the hydraulic fracturing process. We cannot predict whether any such legislation will be enacted and if so, what its provisions would be. Additional levels of regulation and permits required through the adoption of new laws and regulations at the federal, state or local level could lead to delays, increased operating costs and process prohibitions that could reduce the volumes of crude oil and natural gas that move through our gathering systems and decrease demand for our water services, which in turn could materially adversely impact our revenues.

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Protected Species
Laws to protect certain species restrict activities that may affect those species or their habitats. 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.
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 customers, 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, we were entitled to indemnification from Noble for failure of 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 obligation was limited to losses communicated to Noble prior to the third anniversary of the closing of the IPO and was subject to a $500,000 aggregate deductible before we were 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 our customers to execute their drilling and development plans and increase operating expenses associated with repairs or anti-freezing operations.
Customers
See Item 8. Financial Statements and Supplementary Data – Note 2. Summary of Significant Accounting Policies and Basis of Presentation.
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 as 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.
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Human Capital Resources
The officers of our General Partner manage our operations and activities. All of the employees required to conduct and support our operations, including our Named Executive Officers, are employed by Chevron and are subject to the operational services and secondment agreement and omnibus agreement. As of December 31, 2020, Chevron employed approximately 225 people who provide direct support to our operations pursuant to the operational services and secondment agreement and omnibus agreement. See Item 10. Directors, Executive Officers and Corporate Governance and Item 11. Executive Compensation for further discussion of our Named Executive Officers.
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. Prior to the Chevron Merger, our insurance coverage was purchased through a captive insurance company. Subsequent to the Chevron Merger, we have purchased standalone insurance coverage, which includes policies from both commercial market insurance companies and captive insurance companies. We will continue to evaluate our policy limits and deductibles as they relate to the overall cost and scope of our insurance program.
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
Risk Factor Summary
Before you invest in our Common Units, you should carefully consider the risk factors referenced below and as more fully described in this section. If any of the risks referenced below and discussed under this section were to occur, our business, financial condition, results of operations, cash flows and ability to make cash distributions could be materially adversely affected.
Risks Related to Our Business
Following the closing of the Chevron Merger, Chevron Corporation indirectly owns our General Partner. Chevron’s ownership of our General Partner may result in conflicts of interest.
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.
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.
We may not generate sufficient distributable cash flow to enable us to make quarterly distributions to our unitholders at our current distribution rate.
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.
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.
While we have been granted a right of first refusal to provide midstream services and purchase assets on certain acreage that Noble currently owns and on certain 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 or we may not be able to economically accept such an offer from Noble.
We may be unable to grow by acquiring midstream assets retained, acquired or developed by Noble and we may be unable to make attractive acquisitions or successfully integrate acquired businesses, assets or properties, all of which could limit our ability to increase our distributable cash flow.
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. Further, 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.
To 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.
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.
Our business, including the rates of our regulated assets, our pipelines and our environmental and safety practices, are subject to regulation by multiple governmental agencies, which any such regulation could adversely impact our business, results of operations and financial condition.
Our investments in joint ventures involve numerous risks that may affect the ability of such joint ventures to make distributions to us.
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.
Restrictions in our revolving credit facility and term loan credit facility, as well as debt we incur now or in the future, could adversely affect our business, financial condition, results of operations and ability to make quarterly cash distributions to our unitholders.
Our business involves many hazards and operational risks, some of which may not be fully covered by insurance. The occurrence of a significant accident or other event that is not fully insured could curtail our operations and have a material adverse effect on our ability to make cash distributions and, accordingly, the market price for our Common Units.
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.
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Terrorist attacks, cyber incidents or cyber-attacks could have a material adverse effect on our business, financial condition or results of operations, and a cyber incident could result in information theft, data corruption, operational disruption and/or financial loss.
Events outside of our control, including a pandemic, epidemic or outbreak of an infectious disease, such as the recent global outbreak of COVID-19, political unrest and economic recessions occurring around the globe, could have a material adverse impact on our financial position, results of operations and cash flows.
Our and our customers' operations are subject to a series of risks related to climate change and associated government action that could result in increased operating costs, limit the areas in which oil and natural gas production may occur, and reduce the demand for the products and services we provide.
Risks Inherent in an Investment in Us
There can be no assurances that we will enter into a definitive agreement with Chevron related to Chevron’s proposal to acquire all of our Common Units that it does not already own, or that we will complete any transaction contemplated by such an agreement.
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, including with respect to business opportunities. Additionally, we have no control over the business decisions and operations of Noble, and Noble is under no obligation to adopt a business strategy that favors us.
We expect to distribute a substantial portion of our cash available for distribution, which could limit our ability to grow and make acquisitions.
Our partnership agreement provides limited voting rights to our unitholders, restricts the remedies available to unitholders and restricts the voting rights of certain unitholders owning 20% or more of our Common Units.
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. Furthermore, our General Partner’s discretion in establishing cash reserves may reduce the amount of cash we have available to distribute to unitholders.
Our General Partner interest or the control of our General Partner may be transferred to a third party without unitholder consent.
We may issue an unlimited number of additional partnership interests without unitholder approval, which would dilute unitholder interests. Noble may also sell Common Units in the public or private markets, which may adversely impact the trading price of our Common Units.
Our General Partner has a call right that may require our unitholders to sell their Common Units at an undesirable time or price.
Unitholders may have to repay distributions that were wrongfully distributed to them, and Common 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.
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 and provides that unitholders irrevocably waive the right to trial by jury in any claim, suit, action or proceeding under either state or federal laws, both of which may limit the legal recourses available to our unitholders.
Tax Risks
Our tax treatment depends on our status as a partnership for federal income tax purposes, and not being subject to a material amount of entity-level taxation. Our cash available for distribution to unitholders may be substantially reduced if we become subject to entity-level taxation as a result of the Internal Revenue Service (“IRS”) treating us as a corporation or legislative, judicial or administrative changes, and may also be reduced by any audit adjustments if imposed directly on the partnership.
Even if unitholders do not receive any cash distributions from us, unitholders will be required to pay taxes on their share of our taxable income. A unitholder’s share of our taxable income may be increased as a result of the IRS successfully contesting any of the federal income tax positions we take.
Tax-exempt entities and non-U.S. unitholders face unique tax issues from owning our Common Units that may result in adverse tax consequences to them.

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Risks Related to Our Business
Following the closing of the Chevron Merger, Chevron Corporation indirectly owns our General Partner. Chevrons indirect ownership of our General Partner may result in conflicts of interest.
Following the closing of the Chevron Merger, the directors and officers of our General Partner and its affiliates have duties to manage our General Partner in a manner that is beneficial to Chevron, who is the indirect owner of our General Partner. At the same time, our General Partner has duties to manage us in a manner that is beneficial to our unitholders. Therefore, our General Partner’s duties to us may conflict with the duties of its officers and directors to Chevron. As a result of these conflicts of interest, our General Partner may favor the interests of Chevron or its owners or affiliates over the interest of our unitholders.
Now that the Chevron Merger has been completed, our future prospects will depend on Chevron’s growth strategy, midstream operational philosophy, and drilling program, including the level of drilling and completion activity by Chevron on acreage dedicated to us. Additional conflicts also may arise in the future associated with future business opportunities that are pursued by Chevron and us.
We derive a substantial portion of our revenue from Noble. If Noble changes its business strategy, alters its current drilling and development plan on our dedicated acreage, or otherwise significantly reduces the volumes of crude oil, natural gas, produced water or fresh water with respect to which we perform midstream services, our revenue would decline and our business, financial condition, results of operations, cash flows and ability to make distributions to our unitholders would be materially and adversely affected.
A substantial portion of our commercial agreements are with Noble or its affiliates. Accordingly, because we derive a substantial portion of our revenue from our commercial agreements with Noble, we are subject to the operational and business risks of Noble, the most significant of which include the following:
a reduction in or slowing of Noble’s drilling and development plan on our dedicated acreage, which would directly and adversely impact demand for our midstream services;
the volatility of crude oil, natural gas and NGL prices, which could have a negative effect on Noble’s drilling and development plan on our dedicated acreage or Noble’s ability to finance its operations and drilling and completion costs on our dedicated acreage;
the availability of capital on an economic basis to fund Noble’s exploration and development activities;
drilling and operating risks, including potential environmental liabilities, associated with Noble’s operations on our dedicated acreage;
downstream processing and transportation capacity constraints and interruptions, including the failure of Noble to have sufficient contracted processing or transportation capacity; and
adverse effects of increased or changed governmental and environmental regulation or enforcement of existing regulation.
In addition, we are indirectly subject to the business risks of Noble generally and other factors, including, among others:
Noble’s financial condition, credit ratings, leverage, market reputation, liquidity and cash flows;
Noble’s ability to maintain or replace its reserves;
adverse effects of governmental and environmental regulation on Noble’s upstream operations; and
losses from pending or future litigation.
Further, we have no control over Noble’s business decisions and operations, and Noble is under no obligation to adopt a business strategy that is favorable to us. Thus, we are subject to the risk of cancellation of planned development, breach of commitments with respect to future dedications; and other non-payment or non-performance by Noble, including with respect to our commercial agreements, which do not contain minimum volume commitments. Noble is currently 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.
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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.
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. For example, in response to the unprecedented impact on our business from the significant decline in commodity prices and the COVID-19 outbreak, on March 25, 2020, the Board of Directors of our General Partner approved a 73% reduction of the quarterly distribution to $0.1875 per unit for the first quarter 2020. We maintained the reduced quarterly distribution for the second, third and fourth quarter 2020.
The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:
the volumes of natural gas we gather or process, the volumes of crude oil we gather and sell, the volumes of produced water we collect, clean or dispose of, the volumes of fresh water we distribute and store, and the number of wells that have access to our crude oil treating facilities;
our ability to construct new midstream assets that result in revenue increases while navigating regulatory, environmental, political, contractual, legal and economic risks;
market prices of crude oil, natural gas and NGLs and their effect on our customers’ drilling and development plans on our dedicated acreage and the volumes of hydrocarbons that are produced on our dedicated acreage and for which we provide midstream services;
our customers’ ability to fund their drilling and development plans on our dedicated acreage;
the rate at which our customers develop acreage that is dedicated to us or whether our customers will decide to develop areas not dedicated to us;
downstream processing and transportation capacity constraints and interruptions, including the failure of our customers to have sufficient contracted processing or transportation capacity or failure of our gathered volumes to meet quality requirements of such processing and transportation;
the levels of our operating expenses, maintenance expenses and general and administrative expenses;
regulatory action affecting: (i) the supply of, or demand for, crude oil, natural gas, NGLs and water, (ii) the rates we can charge for our midstream services, (iii) the terms upon which we are able to contract to provide our midstream services, (iv) our existing gathering and other commercial agreements or (v) our operating costs or our operating flexibility;
the rates we charge third parties for our midstream services;
prevailing economic conditions; and
adverse weather conditions.
In addition, the actual amount of distributable cash flow that we generate will also depend on other factors, some of which are beyond our control, including:
global or national health pandemics, epidemics or concerns, such as the recent COVID-19 outbreak, which has reduced and may further reduce demand for oil and natural gas and related products due to reduced global or national economic activity;
limited production cuts and freezes implemented by OPEC members and other large oil producers such as Russia;
the level and timing of our capital expenditures;
our debt service requirements and other liabilities;
our ability to borrow under our debt agreements to fund our capital expenditures and operating expenditures and to pay distributions;
fluctuations in our working capital needs;
restrictions on distributions contained in any of our debt agreements;
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the cost of acquisitions, if any;
the fees and expenses of our General Partner and its affiliates (including Noble) that we are required to reimburse;
the amount of cash reserves established by our General Partner; and
other business risks affecting our cash levels.
Because of the natural decline in production from existing wells, our success, in part, depends on our ability to maintain or increase hydrocarbon throughput volumes on our midstream systems, which depends on our customers’ levels of development and completion activity on our dedicated acreage.
The level of crude oil and natural gas volumes handled by our midstream systems depends on the level of production from crude oil and natural gas wells dedicated to our midstream systems, which may be less than expected and which will naturally decline over time. In order to maintain or increase throughput levels on our midstream systems, we must obtain production from wells completed by Noble and any third-party customers on acreage dedicated to our midstream systems or execute agreements with other third parties in our areas of operation.
We have no control over Noble’s or other producers’ levels of development and completion activity in our areas of operation, the amount of reserves associated with wells connected to our systems or the rate at which production from a well declines. In addition, we have no control over Noble or other producers or their exploration and development decisions, which may be affected by, among other things:
the availability and cost of capital;
global or national health pandemics, endemics or concerns, such as the recent COVID-19 outbreak, which has reduced and may further reduce demand for oil and natural gas and related products due to reduced global or national economic activity;
limited production cuts and freezes implemented by OPEC members and other large oil producers such as Russia;
increased volatility of prevailing and projected crude oil, natural gas and NGL prices;
demand for crude oil, natural gas and NGLs, which has been significantly depressed due to the global economic conditions;
levels of reserves;
geologic considerations;
changes in the strategic importance our customers assign to development in the DJ Basin or the Delaware Basin as opposed to their other operations, which could adversely affect the financial and operational resources our customers are willing to devote to development of our dedicated acreage;
increased levels of taxation related to the exploration and production of crude oil, natural gas and NGLs in our areas of operation;
environmental or other governmental regulations, including the availability of permits, the regulation of hydraulic fracturing and a governmental determination that multiple facilities are to be treated as a single source for air permitting purposes; and
the costs of producing crude oil, natural gas and NGLs and the availability and costs of drilling rigs and other equipment.
Producers, including Noble, are also subject to other risks enumerated herein. 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.
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.
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While we have been granted a right of first refusal to provide midstream services on certain acreage that Noble currently owns and on certain 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 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.
We may be unable to make attractive acquisitions or successfully integrate acquired businesses, assets or properties, and any ability to do so may disrupt our business and hinder our ability to grow and an acquisition from Noble or a third party may reduce, rather than increase, our distributable cash flow or may disrupt our business.
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. Any acquisition involves potential risks that may disrupt our business, including the following, among other things:
mistaken assumptions about volumes or the timing of those volumes, revenues or costs, including synergies;
an inability to successfully integrate the acquired assets or businesses;
the assumption of unknown liabilities;
exposure to potential lawsuits;
limitations on rights to indemnity from the seller;
the diversion of management’s and employees’ attention from other business concerns;
unforeseen difficulties operating in new geographic areas; and
customer or key employee losses at the acquired businesses.
We may not be able to attract dedications of additional third-party volumes, in part because our industry is highly competitive, which could limit our ability to grow and increase our dependence on Noble. Further, 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.
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 continue to 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
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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 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.
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.
To 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 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 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. For example, the significant volatility in energy commodity prices in recent years combined with environmental, social and governance concerns about the oil and gas industry has led to negative investor sentiment and an adverse impact on the ability of companies in the oil and gas industry to seek financing and access the capital markets on favorable terms or at all. 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. 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
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for financial accounting purposes, and conversely, we might fail to make cash distributions during periods when we record net income for financial accounting purposes.
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 area 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, 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 revoke the waiver, either at the request of other entities or on its own initiative. 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. 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. In addition, if any of our waivers are revoked, the FERC's Revised Policy Statement on the Treatment of Income Taxes 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. Additionally, as part of the Consolidated Appropriations Act of 2021, Congress reauthorized PHMSA through 2023 and directed the agency to move forward with several regulatory actions, including the “Pipeline Safety: Class Location Change Requirements” and the “Pipeline Safety: Safety of Gas Transmission and Gathering Pipelines” proposed rulemakings. Congress has also instructed PHMSA to issue final regulations that will require operators of non-rural gas gathering lines and new and existing transmission and distribution pipeline facilities to conduct certain leak detection and repair programs and to require facility inspection and maintenance plans
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to align with those regulations. 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.
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.
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.
Historically, crude oil, natural gas and NGL prices have been volatile and subject to wide fluctuations. For example, the significant decline in crude oil prices during 2020 has largely been attributable to the actions of Saudi Arabia and Russia, which have resulted in a substantial decrease in crude oil and natural gas prices, and the global outbreak of COVID-19, which has reduced demand for crude oil and natural gas because of significantly reduced global and national economic activity. While commodity prices have experienced some increased stability recently, we cannot predict whether or when commodity prices and economic activities will return to normalized 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.
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.
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;
the macroeconomic factors affecting our current and potential customers;
the balance of supply and demand, on a short-term, seasonal and long-term basis, in our markets;
the extent to which the customers in our markets are willing to contract on a long-term basis; and
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.
Our business involves many hazards and operational risks, some of which may not be fully covered by insurance. The occurrence of a significant accident or other event that is not fully insured could curtail our operations and have a material adverse effect on our ability to make cash distributions and, accordingly, the market price for our Common Units.
Our operations are subject to all of the hazards inherent in the gathering of crude oil, natural gas and produced water and the delivery and storage of fresh water, including:
damage to, loss of availability of and delays in gaining access to pipelines, centralized gathering facilities, pump stations, related equipment and surrounding properties caused by design, installation, construction materials or operational flaws, natural disasters, acts of terrorism or acts of third parties;
mechanical or structural failures at our or Noble’s facilities or at third-party facilities on which our customers’ or our operations are dependent, including electrical shortages, power disruptions and power grid failures;
leaks of crude oil, natural gas, NGLs or produced water or losses of crude oil, natural gas, NGLs or produced water as a result of the malfunction of, or other disruptions associated with, equipment or facilities;
unexpected business interruptions;
curtailments of operations due to severe seasonal weather;
riots, strikes, lockouts or other industrial disturbances;
fires, ruptures and explosions; and
other hazards that could also result in personal injury and loss of life, pollution and suspension of operations.
Any of these risks could adversely affect our ability to conduct operations or result in substantial loss to us as a result of claims for:
injury or loss of life;
damage to and destruction of property, natural resources and equipment;
pollution and other environmental damage;
regulatory investigations and penalties;
suspension of our operations; and
repair and remediation costs.
We may elect not to obtain insurance for any or all of these risks if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. The occurrence of an event that is not fully covered by insurance could have a material adverse effect on our business, financial condition, results of operations, cash flows and ability to make cash distributions.
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 the land on which our pipeline and facilities are located 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.
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.
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A cyber incident could result in information theft, data corruption, operational disruption and/or financial loss.
The oil and gas industry has become increasingly dependent on digital technologies to conduct day-to-day operations including certain midstream activities. For example, software programs are used to manage gathering and transportation systems and for compliance reporting. The use of mobile communication devices has increased rapidly. Industrial control systems such as SCADA (supervisory control and data acquisition) now control large scale processes that can include multiple sites and long distances, such as oil and gas pipelines.
We depend on digital technology, including information systems and related infrastructure as well as cloud applications and services, to process and record financial and operating data and to communicate with our employees and business partners. Our business partners, including vendors, service providers, and financial institutions, are also dependent on digital technology. The technologies needed to conduct midstream activities make certain information the target of theft or misappropriation.
As dependence on digital technologies has increased, cyber incidents, including deliberate attacks or unintentional events, also has increased. A cyber attack could include gaining unauthorized access to digital systems for purposes of misappropriating assets or sensitive information, corrupting data, or causing operational disruption, or result in denial-of-service on websites. SCADA-based systems are potentially vulnerable to targeted cyber attacks due to their critical role in operations.
Our technologies, systems, networks, and those of our business partners may become the target of cyber attacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or other disruption of our business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period.
A cyber incident involving our information systems and related infrastructure, or that of our business partners, could disrupt our business plans and negatively impact our operations in the following ways, among others:
a cyber attack on a vendor or service provider could result in supply chain disruptions which could delay or halt development of additional infrastructure, effectively delaying the start of cash flows from the project;
a cyber attack on downstream pipelines could prevent us from delivering product at the tailgate of our facilities, resulting in a loss of revenues;
a cyber attack on a communications network or power grid could cause operational disruption resulting in loss of revenues;
a deliberate corruption of our financial or operational data could result in events of non-compliance which could lead to regulatory fines or penalties; and
business interruptions could result in expensive remediation efforts, distraction of management, damage to our reputation, or a negative impact on the price of our units.
Our implementation of various controls and processes, including globally incorporating a risk-based cyber security framework, to monitor and mitigate security threats and to increase security for our information, facilities and infrastructure is costly and labor intensive. Moreover, there can be no assurance that such measures will be sufficient to prevent security breaches from occurring. As cyber threats continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any information security vulnerabilities.
Events outside of our control, including a pandemic, epidemic or outbreak of an infectious disease, such as the recent global outbreak of COVID-19, political unrest and economic recessions occurring around the globe, could have a material adverse impact on our financial position, results of operations and cash flows.
The U.S. and other world economies are experiencing recessions due to the global outbreak of COVID-19, which began late in 2019. In March 2020, OPEC and non-OPEC producers failed to agree to production cuts, causing a significant drop in crude oil prices. Subsequently, certain of these producers agreed to long-term production cuts and, most recently, Saudi Arabia announced additional production costs in January 2021. While these production cuts could rebalance the market in the long-term, in the short-term, we do not believe they will be large enough to offset the sharp decrease in demand caused by COVID-19. Additionally, recent acts of protest and civil unrest related to the 2020 presidential election have caused economic and political disruption in the United States. These factors collectively have contributed to unprecedented negative global economic impacts, including a significant drop in hydrocarbon product demand, which may extend into the future.
Recessions would likely extend the time for the current oil markets to absorb excess supplies and rebalance inventory resulting in decreased demand for our midstream services for a number of future quarters. Our profitability will likely be significantly affected by this decreased demand and could lead to material impairments of our long-lived assets, intangible assets and equity method investments. Additionally, these factors could lead to further reductions in our distributions to unitholders or may cause us to fall out of compliance with the covenants in our revolving credit facility and term loans. The global outbreak of COVID-19 and impact of lower commodity prices could lead to disruptions in our supply network, including, among other things, storage and pipeline constraints brought on by overproduction and decreased demand from refiners.
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Our future access to capital, as well as that of our partners and contractors, could be limited due to tightening capital markets that could delay or inhibit our capital projects.
The outbreak of COVID-19 could potentially further impact our workforce. The infection of key personnel, or the infection of a significant amount of our workforce, could have a material adverse impact on our business, financial condition and results of operations. Much of our workforce is working remotely until the risks of COVID-19 are reduced. Additionally, in response to reduced development and activity levels stemming from the commodity price environment, a number of our employees were placed on furlough or part-time work programs. A remote workforce combined with workforce reduction programs could introduce risks to achieving business objectives and/or the ability to maintain our controls and procedures. For example, the technology required for the transition to remote work increases our vulnerability to cybersecurity threats, including threats of unauthorized access to sensitive information or to render data or systems unusable, the impact of which may have material adverse effects on our business and operations. See “A cyber incident could result in information theft, data corruption, operational disruption and/or financial loss” above.
The impacts of COVID-19 and the significant drop in commodity prices has had an unprecedented impact on the global economy and our business. We are unable to predict all potential impacts to our business, the severity of such impacts or duration.
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.
In 2019, Colorado adopted SB 181, which 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. In keeping with SB 181, the COGCC in November 2020 adopted revisions to several regulations to increase protections for public health, safety, welfare, wildlife, and environmental resources. Most significantly, these revisions establish more stringent setbacks (2,000 feet, instead of the prior 500-foot) on new oil and gas development and eliminate routine flaring and venting of natural gas at new and existing wells across the state, each subject to only limited exceptions. Some local communities have adopted, or are considering adopting, further restrictions for oil and gas activities, such as requiring greater setbacks.
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 and the current U.S. Administration has announced plans to take certain actions to further regulate or constrain hydraulic fracturing operations. 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.
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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, the imposition of certain restrictions on operations to prevent impacts to protected species, and the imposition of substantial liabilities and remedial obligations for pollution or contamination resulting from our and our customers’ operations. Failure to comply with these laws, regulations and permits may result in joint and several or strict liability or the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, or the issuance of injunctions or administrative orders limiting or preventing some or all of our operations. Private parties, including the owners of the properties through which our gathering systems pass, may also have the right to pursue legal actions to enforce compliance, as well as to seek damages for non-compliance, with environmental laws and regulations or for personal injury or property damage. We may not be able to recover all or any of these costs from insurance. In addition, we may experience a delay in obtaining or be unable to obtain required permits, which may cause us to lose potential and current customers, interrupt our operations or limit our growth and revenues, which in turn could affect the amount of cash we have available for distribution. We cannot provide any assurance that changes in or additions to public policy regarding the protection of the environment, worker health and safety, and impacts to hydraulic fracturing, permitting, and GHG emissions, will not have a significant impact on our operations and the amount of cash we have available for distribution. It is possible that our operations and those of our customers may be subject to greater environmental, health, and safety restrictions.
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. 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 related to climate change and associated government action 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.
Climate change-related issues continue 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, various federal agencies, 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. For more information, see our regulatory disclosure titled Climate Change and Air Quality Standards. Such actions could include limits on emissions and curtailment of the production of oil and gas, such as through the cessation of leasing public land for hydrocarbon development. For more information, see our regulatory disclosure titled Hydraulic Fracturing. Other actions that could be pursued include more restrictive requirements for the development of pipeline infrastructure or LNG export facilities. 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.
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At the international level, the United Nations-sponsored “Paris Agreement” requires member states to individually determine and submit non-binding emissions reduction targets every five years after 2020. Although the United States had previously withdrawn from the Paris Agreement, an executive order was signed on January 20, 2021 recommitting the United States to the agreement. The impacts of this order, and any legislation or regulation that may be adopted as a result, are unclear at this time. However, 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.
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. There is also a risk that financial institutions will be required to adopt policies that have the effect of reducing the funding provided to the fossil fuel sector. A material reduction in the capital available to the fossil fuel industry could make it more difficult to secure funding for exploration, development, production, transportation, and processing activities, which could result in decreased demand for our midstream services. 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. In addition, while our consideration of changing weather conditions and inclusion of safety factors in design covers the uncertainties that climate change and other events may potentially introduce, our ability to mitigate the adverse impacts of these events depends in part on the effectiveness of our facilities and our disaster preparedness and response and business continuity planning, which may not have considered or be prepared for every eventuality. See Items 1. and 2. Business and Properties – Regulations.
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.
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.
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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 asset inspection, maintenance or repair costs may increase in the future. In addition, there could be service interruptions due to unforeseen events or conditions or increased downtime associated with our pipelines that could have a material adverse effect on our business and results of operations.
Gathering systems, pipelines and facilities are generally long-lived assets, and construction and coating techniques have varied over time. Depending on the condition and results of inspections, some assets will require additional maintenance, which could result in increased expenditures in the future. Any significant increase in these expenditures could adversely affect our results of operations, financial position or cash flows, as well as our ability to make cash distributions to our unitholders. 
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.
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 Robin H. Fielder, our Chief Executive Officer, Thomas W. Christensen, our Chief Financial Officer, John S. Reuwer, our Vice President of Business and Corporate Development, 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 Chevron.
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 Chevron to conduct our business and activities.
Chevron 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 Chevron. If our General Partner and the officers and employees of Chevron do not devote sufficient attention to the management and operation of our business and activities, our business, financial condition, results of operations, cash flows and ability to make cash distributions could be materially adversely affected.
Debt we incur in the future may limit our flexibility to obtain financing and to pursue other business opportunities.
Our future level of debt could have important consequences to us, including the following:
our ability to obtain additional financing, if necessary, for working capital, capital expenditures (including building additional gathering pipelines needed for required connections and building additional centralized gathering facilities pursuant to our gathering agreements) or other purposes may be impaired or such financing may not be available on favorable terms;
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our funds available for operations, future business opportunities and distributions to unitholders will be reduced by that portion of our cash flow required to make interest payments on our debt;
we may be more vulnerable to competitive pressures or a downturn in our business or the economy generally; and
our flexibility in responding to changing business and economic conditions may be limited.
Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service any future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying our business activities, investments or capital expenditures, selling assets or issuing equity. We may not be able to effect any of these actions on satisfactory terms or at all.
Increases in interest rates could adversely affect our business.
We have exposure to increases in interest rates. As of December 31, 2020, $710 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 $16.7 million increase in interest expense for the year ended December 31, 2020. 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.
Risks Inherent in an Investment in Us
There can be no assurances that we will enter into a definitive agreement with Chevron related to Chevron’s proposal to acquire all of our Common Units that it does not already own, or that we will complete any transaction contemplated by such an agreement.
On February 4, 2021, the board of directors of our General Partner received a non-binding proposal (the “Proposal”) from Chevron Corporation, pursuant to which Chevron would acquire all our Common Units that Chevron and its affiliates do not already own. While the Conflicts Committee has been engaged by our General Partner to evaluate the Proposal and any potential transaction with Chevron related to the Proposal (the “Potential Transaction”), there can be no assurances that we will enter into a definitive agreement with Chevron related to any Potential Transaction. Furthermore, should we enter into a definitive agreement with Chevron, we anticipate that the consummation of any Potential Transaction will be subject to a number of conditions, and there can be no assurances that such conditions will be satisfied or waived or that any Potential Transaction will be completed in a timely manner or at all.
Our General Partner and its affiliates 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 Chevron, and Chevron is under no obligation to adopt a business strategy that favors us.
Chevron indirectly owns an aggregate 62.6% limited partner interest in us. In addition, Chevron, indirectly, owns 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. Conflicts of interest may arise between Chevron 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 Chevron, over the interests of our common unitholders. These conflicts include, among others, the following situations:
neither our partnership agreement nor any other agreement requires Chevron to pursue a business strategy that favors us or utilizes our assets, which could involve decisions by Chevron 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. Chevron’s directors and officers have a fiduciary duty to make these decisions in the best interests of the stockholders of Chevron;
Chevron may be constrained by the terms of its debt instruments from taking actions, or refraining from taking actions, that may be in our best interests;
our partnership agreement replaces the fiduciary duties that would otherwise be owed by our General Partner with contractual standards governing its duties and limits our General Partner’s liabilities and the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty under applicable Delaware law;
except in limited circumstances, our General Partner has the power and authority to conduct our business without unitholder approval;
our General Partner will determine the amount and timing of, among other things, cash expenditures, borrowings and repayments of indebtedness, the issuance of additional partnership interests, the creation, increase or reduction in cash
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reserves in any quarter and asset purchases and sales, each of which can affect the amount of cash that is available for distribution to unitholders;
our General Partner will determine which costs incurred by it are reimbursable by us;
our General Partner may cause us to borrow funds in order to permit the payment of cash distributions;
our partnership agreement does not restrict our General Partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf;
our General Partner intends to limit its liability regarding our contractual and other obligations;
our General Partner may exercise its right to call and purchase all of the Common Units not owned by it and its affiliates if it and its affiliates own more than 80% of the Common Units;
our General Partner controls the enforcement of obligations owed to us by our General Partner and its affiliates, including our gathering agreements with Noble, the ROFR and ROFO; and
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 Chevron 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 Chevron 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, Chevron and other affiliates of our General Partner may acquire, construct or dispose of additional midstream assets in the future without any obligation to offer us the opportunity to purchase any of those assets (except to the extent the ROFR or ROFO pertain to such assets). As a result, competition from Chevron 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.
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Our partnership agreement contains provisions that restrict the remedies available to unitholders for actions taken by our General Partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our partnership agreement provides that:
whenever our General Partner makes a determination or takes, or declines to take, any other action in its capacity as our General Partner, our General Partner is required to make such determination, or take or decline to take such other action, in good faith, meaning that it subjectively believed that the determination or the decision to take or decline to take such action was not adverse to the interests of our partnership, and will not be subject to any other or different standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity;
our General Partner will not have any liability to us or our unitholders for decisions made in its capacity as a General Partner so long as it acted in good faith;
our General Partner and its officers and directors will not be liable for monetary damages or otherwise to us or our limited partners resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our General Partner or its officers and directors, as the case may be, acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and
our General Partner will not be in breach of its obligations under our partnership agreement or its fiduciary duties to us or our limited partners if a transaction with an affiliate or the resolution of a conflict of interest is approved in accordance with, or otherwise meets the standards set forth in, our partnership agreement.
In connection with a situation involving a transaction with an affiliate or a conflict of interest, other than one where our General Partner is permitted to act in its sole discretion, our partnership agreement provides that any determination by our General Partner must be made in good faith. If an affiliate transaction or the resolution of a conflict of interest is not approved by our common unitholders or the conflicts committee, then it will be presumed that, in making its decision, taking any action or failing to act, the board of directors of our General Partner acted in good faith and in any proceeding brought by or on behalf of any limited partner or the Partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.
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 our 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.
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 Chevron for the provision of certain administrative support services to us. Under our operational services and secondment agreement, we will be required to reimburse Chevron 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.
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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 23% 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. Chevron indirectly 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 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 Chevron to transfer its membership interest in our General Partner to a third party. The new owner of our General Partner would then be in a position to replace the board of directors and officers of our General Partner with its own choices.
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 Chevron:
management of our business may no longer reside solely with our current General Partner; and
affiliates of the newly admitted General Partner may compete with us, and neither that General Partner nor such affiliates will have any obligation to present business opportunities to us except with respect to rights of first refusal contained in our omnibus agreement.
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
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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.
Chevron 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.
Chevron indirectly owns 56,447,616 Common Units. 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.
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.
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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, 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.
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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.
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 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. However, no ruling has been or will be requested regarding our treatment as a partnership for U.S. federal income tax purposes. Failing to meet the qualifying income requirement or a change in current law could cause us to be treated as a corporation for U.S. federal income tax purposes or otherwise subject us to taxation as an entity.
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. Distributions to our unitholders would generally be taxed again as corporate distributions, 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. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our Common Units.
At the state level, several states have been evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise 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.
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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 changes or differing interpretations at any time. Members of Congress have frequently proposed and considered substantive changes to the existing U.S. federal income tax laws that would affect publicly traded partnerships, including proposals that would eliminate our ability to qualify for partnership tax treatment.
In addition, the Treasury Department has issued, and in the future may issue, regulations interpreting those laws that affect publicly traded partnerships. There can be no assurance that there will not be further changes to U.S. federal income tax laws or the Treasury Department’s interpretation of the qualifying income rules in a manner that could impact our ability to qualify as a partnership in the future.
Any modification to the U.S. federal income tax laws and interpretations thereof may or may not be retroactively applied and could make it more difficult or impossible for us to meet the exception 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.
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.
Our unitholders are required to pay any U.S. federal income taxes and, in some cases, state and local income taxes, on their share of our taxable income, whether or not they receive cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income.
If the IRS contests the 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 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 the positions we take. A court may not agree with some or all of the positions we take. Any contest with the IRS may materially and adversely impact the market for our Common Units and the price at which they trade. 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.
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. Tax exempt entities should consult a tax advisor before investing in our Common Units.
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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 unitholders’ allocable share of our net taxable income decrease unitholders’ 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 Common 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. Net capital loss may only offset capital gains and, in the case of individuals, up to $3,000 of ordinary income per year. In the taxable period in which a unitholder sells its units, such unitholder may recognize ordinary income from our allocations of income and gain to such unitholder prior to the sale and from recapture items that generally cannot be offset by any capital loss recognized upon the sale of units.
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, subject to certain exemptions in the Coronavirus Aid, Relief, and Economic Security Act (the “CARES Act” discussed below), 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.
For our 2020 taxable year, the CARES Act increases the 30% adjusted taxable income limitation to 50%, unless we elect not to apply such increase. For purposes of determining our 50% adjusted taxable income limitation, we may elect to substitute our 2020 adjusted taxable income with our 2019 adjusted taxable income, which may result in a greater business interest expense deduction. In addition, unitholders may treat 50% of any excess business interest allocated to them in 2019 as deductible in the 2020 taxable year without regard to the 2020 business interest expense limitations. The remaining 50% of such unitholder’s excess business interest is carried forward and subject to the same limitations as other taxable years.
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.
Non-U.S. unitholders will be subject to U.S. federal income taxes and withholding with respect to their income and gain from owning our Common Units.
Non-U.S. unitholders are generally taxed and subject to income tax filing requirements by the United States on income effectively connected with a U.S. trade or business. Income allocated to our unitholders and 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 tax 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. While the determination of the partner’s “amount realized” generally includes any decrease of a partner’s share of the partnership’s liabilities, recently issued Treasury regulations provide that the “amount realized” on a transfer of an interest in a publicly traded partnership, such as our Common Units, will generally be the amount of gross proceeds paid to the broker effecting the applicable transfer on behalf of the transferor, and thus will be determined without regard to any decrease in that partner’s share of a publicly traded partnership’s liabilities. The Treasury regulations further provide that withholding on a transfer of an interest in a publicly traded partnership will not be imposed on a transfer that occurs prior to January 1, 2022, and after that date, if effected through a broker, the obligation to withhold is imposed on the transferor’s broker.
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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 between transferors and transferees of our Common Units each month based upon the ownership of our Common Units on the first day of each month, instead of on the basis of the date a particular Common Unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.
We generally prorate our items of income, gain, loss and deduction for U.S. federal income tax purposes between transferors and transferees of our Common Units each month based upon the ownership of our Common Units on the first day of each month, instead of on the basis of the date a particular Common Unit is transferred. Treasury Regulations allow a similar monthly simplifying convention, but such regulations do not specifically authorize all aspects of our proration method. If the IRS were to challenge our proration method, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.
A unitholder whose Common Units are the subject of a securities loan (e.g., a loan to a “short seller” to cover a short sale of Common Units) may be considered to have disposed of those Common Units. If so, 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 the subject of a securities loan may be considered to have 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 securities loan 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 will likely be 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 14. Commitments and Contingencies of this Form 10-K, which is incorporated by reference into this Part I, Item 3.
Item 4.  Mine Safety Disclosures
Not Applicable.
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PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Our Common Units trade under the symbol “NBLX” on the Nasdaq. As of December 31, 2020, our units were held by 3 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, 2020, Chevron indirectly owns 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, 2020.
The number of Common Units that are available for issuance under our LTIP as of December 31, 2020 included:
Plan CategoryNumber of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and RightsWeighted-Average Exercise Price of Outstanding Options, Warrants and RightsNumber 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— — 1,484,907 
Equity Compensation Plans Not Approved by Security Holders— — — 
Total— — 1,484,907 
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 22, 2021, the Board of our General Partner declared a quarterly cash distribution of $0.1875 per limited partner unit. The distribution will be paid on February 12, 2021, to unitholders of record on February 5, 2021.
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.
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.
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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. See Item 8. Financial Statements and Supplementary Data – Note 3. Transactions with Affiliates.
Conversion of Subordinated Units
See Item 8. Financial Statements and Supplementary Data – Note 12. Partnership Distributions.

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Item 6. Selected Financial Data
Selected Financial Data for periods prior to September 20, 2016 represent the Contributed Businesses of certain of Noble’s midstream assets as the accounting Predecessor to the Partnership, presented on a carve-out basis of Noble’s historical ownership of the Predecessor. The Predecessor financial data has been prepared from the separate records maintained by Noble. Beginning with 2019, 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)20202019201820172016
Statements of Operations
Total Revenues$764,625 $703,801 $558,735 $289,622 $193,453 
Net Income94,866 245,467 216,719 160,767 96,290 
Net Income Attributable to Noble Midstream Partners LP134,031 159,996 162,734 140,572 28,458 
Net Income Attributable to Limited Partners Per Limited Partner Unit — Basic
Common Units$1.49 $3.09 $3.96 $4.10 $0.89 
Subordinated Units— 3.86 3.96 4.10 0.89 
Cash Distributions Declared per Limited Partner Unit0.7500 2.6144 2.1913 1.8113 0.4333 
Balance Sheet
Cash and Cash Equivalents$16,332 $12,676 $14,761 $20,090 $57,443 
Total Property, Plant and Equipment, Net1,759,349 1,762,957 1,570,923 821,962 380,310 
Investments904,955 660,778 82,317 80,461 11,151 
Intangible Assets, Net245,510 277,900 310,202 — — 
Goodwill— 109,734 109,734 — — 
Total Assets3,037,196 2,926,082 2,192,178 1,038,465 537,430 
Long-Term Debt1,109,652 1,495,679 559,021 85,000 — 
Total Liabilities1,736,845 1,665,221 705,623 251,806 50,368 
Mezzanine Equity119,658 106,005 — — — 
Total Equity1,180,693 1,154,856 1,486,555 786,659 487,062 
Throughput and Crude Oil Sales Volumes
Crude Oil Sales Volumes (Bbl/d)16,964 9,354 6,129 — — 
Crude Oil Gathering Volumes (Bbl/d)228,991 231,963 177,127 69,249 45,236 
Natural Gas Gathering Volumes (MMBtu/d)669,826 631,760 387,804 244,940 180,262 
Total Barrels of Oil Equivalent (Boe/d)314,866 322,312 232,974 100,652 68,347 
Natural Gas Processing Volumes (MMBtu/d)41,511 50,039 61,766 49,531 42,269 
Produced Water Gathering Volumes (Bbl/d)173,639 188,515 121,215 37,365 10,592 
Fresh Water Services Volumes (Bbl/d)91,886 164,524 175,754 155,990 94,227 

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion should be read in conjunction with the consolidated financial statements and accompanying notes included in Part II, Item 8 of this Annual Report. This section of this Annual Report generally discusses 2020 and 2019 items and year-to-year comparisons between 2020 and 2019. Discussions of 2018 items and year-to-year comparisons between 2019 and 2018 that are not included in this Annual Report can be found in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Part II, Item 7 of the Partnership’s Annual Report on Form 10-K for the fiscal year ended December 31, 2019.
Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) is intended to provide a narrative about our business from the perspective of our management. Our MD&A is presented in the following major sections:
Executive Overview and Operating Outlook;
Results of Operations;
Liquidity and Capital Resources; and
Critical Accounting Policies and Estimates.
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 and 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 AND OPERATING OUTLOOK
Impact of COVID-19 and Declining Commodity Prices
Our business was highly impacted by the COVID-19 pandemic and the decline in commodity prices.
COVID-19 Ongoing containment measures and responsive actions to the COVID-19 pandemic continue to contribute to severe declines in general economic activity and energy demand. As a result, the global economy has experienced a slowing of economic growth, disruption of global manufacturing supply chains, stagnation of crude oil and natural gas consumption and interference with workforce continuity.
The virus continues to impact the global demand for commodities, a trend we expect to continue into 2021. Additionally, the risks associated with COVID-19 have impacted our workforce and the way we meet our business objectives. In response to this, we executed the following actions:
Remote workforce – Due to concerns over health and safety, much of our workforce continues to work remotely until further notice. Throughout 2020, working remotely did not significantly impact our ability to maintain operations, including use of financial reporting systems, nor did it significantly impact our internal control environment. In addition, certain of our employees and contractors work in remote field locations. We implemented various health and safety protocols including, among others, reduction of certain operational workloads to critical maintenance and personnel, mandating use of certain secure travel options, review of critical medical supplies and procedures and implementation of other safeguards to protect operational personnel. We have not incurred, and in the future do not expect to incur, significant expenses related to business continuity as employees work from home.
Mobilized a Crisis Management Team (“CMT”) – Our corporate CMT is responsible for ensuring the organization implements our corporate Employee Health and Wellness plan elements pertaining to pandemic response. This plan follows the Centers for Disease Control and Prevention (“CDC”), national, state and local guidance in preparing and responding to COVID-19. The CMT implemented communication protocols should an employee become sick, and we continue to follow CDC guidance, which is subject to change in the future. Throughout 2020, we did not experience significant business or operational interruption due to workforce health or safety concerns pertaining to COVID-19.
The rapid and unprecedented decreases in energy demand have continued to impact certain elements of our distribution channels. For example, the significant decline in energy demand has resulted in downstream market impacts as refineries reduced activity or declared force majeure. Additionally, inventory surpluses have, at times, overwhelmed U.S. storage capacity, leading to a further strain on the supply chain.
Commodity Prices The COVID-19 pandemic has continued to cause unprecedented and prolonged declines in the global demand for crude oil and natural gas. While relaxing of certain containment measures resulted in increased demand and commodity prices in the second half of 2020, demand continues to be significantly lower than levels experienced prior to the COVID-19 pandemic. Additional outbreaks and/or a return of more stringent containment measures or further restrictions could negatively impact commodity prices in the near future. The continuing uncertainty regarding the longevity and severity of the impacts of COVID-19 to the crude oil and natural gas industry, including the reduced demand for crude oil and natural gas commodities and its resulting impact on commodity prices, may continue until vaccines or alternative treatments are made widely available across the globe.
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Contemporaneously with the COVID-19 pandemic, the crude oil and natural gas industry continues to be impacted by excess supply in the global marketplace. The Organization of Petroleum Exporting Countries (“OPEC”) and certain non-OPEC producers agreed to production cuts beginning in May 2020 that extend through first quarter 2022. While these production cuts have proven unable to sufficiently offset the ongoing decreases in demand caused by COVID-19, production from these producers has fallen to its lowest levels in decades.
These factors caused a number of producers to reduce capital spending levels and shut-in production at certain fields for a portion of 2020. These temporary shut-ins served to lower inventory levels and thereby alleviate some of the crude oil storage constraints experienced in the beginning of second quarter 2020; however, by third quarter 2020, a number of producers brought back online previously shut-in production. Inventory levels, and resulting storage constraints, could be impacted as producers continue bringing production back online with relatively higher commodity prices.
In addition to the U.S. crude oil market, the U.S. domestic natural gas market continues to be oversupplied and has contributed to depressed pricing. We expect that if development activity remains at lower levels in the U.S. leading to reduced crude oil and associated natural gas production, U.S. domestic natural gas prices will adjust as supply and demand levels equalize.
The sustained decline in commodity prices adversely affected shale producers in the U.S., including our customers. In response, certain of our customers reduced their capital investment programs and temporarily shut-in production. Collectively these actions by our customers have resulted in decreased throughput volumes on our gathering systems and significant decreases in fresh water deliveries due to decreases in well completion activity.
The commodity price environment is expected to remain depressed based on sustained decreases in demand, over-supply and global economic instability caused by COVID-19, discussed further below. In addition, we expect downstream capacity and storage constraints to continue to have a negative impact on the ability to transport production. If constraints continue such that storage becomes unavailable to our customers or commodity prices remain depressed, they may be forced or elect to further shut-in production and delay or discontinue drilling plans, which would result in a further decline in demand for our services.
In this market environment, we are focused on protecting our balance sheet. In response, starting with the first quarter of 2020, the Board of Directors of our General Partner approved a 73% reduction of the quarterly distribution to $0.1875 per unit. We intend to utilize funds from our distribution reduction and maintenance to reduce our debt levels. Our Board of Directors of our General Partner will continue reviewing the quarterly distribution in context of market conditions.
Global Economic Instability COVID-19, coupled with the drop in commodity prices, has contributed to equity market volatility and what experts have now concluded amounted to a recession in first quarter 2020. Estimated ranges of the duration of these impacts to equity markets and the global economy vary widely, especially given the continued impacts of COVID-19 are unknown. Throughout 2020, the U.S. government passed a series of stimulus packages which, collectively, have provided the largest relief packages in U.S. history. These packages include various provisions intended to provide relief to individuals and businesses in the form of tax changes, loans and grants, among others. At this time, we do not believe these stimulus measures will have a material impact on the Partnership; however, we do believe they could aid the economy by providing relief to certain individuals and smaller businesses.
The decline in our unit price and corresponding reduction in our market capitalization were sustained throughout most of 2020, a condition that is consistent across our sector. We do not have any debt covenants or other lending arrangements that depend upon our unit price. Throughout 2020, we remained in compliance with the covenants contained in our revolving credit facility and term loans, which provide that our consolidated leverage ratio as of the end of each fiscal quarter may not exceed 5.00 to 1.0, and our consolidated interest coverage ratio as of the end of each fiscal quarter to be no less than 3.00 to 1.0. The consolidated leverage ratio and consolidated interest coverage ratio are defined in the respective agreements.
As cities, states and countries continue relaxing confinement restrictions, the risk for the resurgence and recurrence of COVID-19 remains. The reinstatement of containment measures could potentially lead to an extended period of reduced demand for crude oil and natural gas commodities, as well as assert further pressure on the global economy.
Potential Future Impacts
Impairment testing involves uncertainties related to key assumptions such as expectations of our customers’ development and capital spending plans, among others, and a significant number of interdependent variables are derived from these key assumptions. There is a high degree of complexity in their application in determining use and value in recovery tests and fair value determinations.
We performed impairment assessments as of March 31, 2020 and fully impaired our goodwill during first quarter 2020. See Item 1. Financial Statements – Note 2. Summary of Significant Accounting Policies and Basis of Presentation. We performed impairment assessments throughout 2020, including assessments of property, plant and equipment, customer-related intangible assets, and equity method investments and did not identify any impairment indicators based on these procedures.
Given the inherent volatility of the current market conditions driven by the COVID-19 pandemic and the oil and gas supply dynamics, the potential for future conditions to deviate from our current assumptions exists. For example, further erosion in
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consumer energy demand, lower crude oil and natural gas development and production, and/or lower commodity prices could trigger future impairments of our assets or non-compliance with the financial covenants in our revolving credit facility and term loans.
Workforce Adjustments
As previously disclosed, the officers of our General Partner manage our operations and activities. In 2020, Noble engaged in corporate restructuring activities, resulting in reductions in its employee and contractor work forces. Additionally, certain employees were participating in furlough and part-time work programs implemented in first quarter 2020 and continued into third quarter 2020. Certain employees that support our operations were impacted by these activities. Additionally, Noble lowered executive leadership salaries by 10% to 20%. Certain officers of our General Partner were impacted by the salary reductions. The aforementioned actions did not significantly impact our ability to maintain operations, including use of financial reporting systems, nor have they significantly impacted our internal control environment.
2020 Significant Results
We accomplished the following significant transactional and financial results for the year ended December 31, 2020.
Significant Transactional Highlights Include:
exercised our 20% option on Saddlehorn, which provided $24.2 million of income and $25.0 million in distributions since February 2020;
Delaware Crossing began delivering crude oil into all connection points in April 2020;
EPIC Y-Grade transitioned back to NGL service beginning in May 2020, with completion of its first new build fractionator in June; and
EPIC Crude entered full service in April 2020;
Significant Financial Highlights Include:
net income of $94.9 million, a decrease of 61% as compared with 2019;
net cash provided by operating activities of $376.6 million, a decrease of 2% as compared with 2019;
Adjusted EBITDA (non-GAAP financial measure) of $425.8 million, an increase of 10% as compared with 2019;
Adjusted EBITDA (non-GAAP financial measure) attributable to the partnership of $392.9 million, an increase of 54% as compared with 2019; and
distributable cash flow (non-GAAP financial measure) of $326.2 million, an increase of 53% as compared with 2019.
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
In addition to our transactional and financial achievements, we remained focused on environmental, social and governance initiatives by identifying opportunities to reduce environmental impact, improve safety and support the communities in which we operate through social investment. In 2020, we reduced flaring intensity in the Delaware Basin by 53% compared to 2019, while reducing overall emissions and increasing natural gas throughput from the field.
2021 Capital Program
Organic Capital Program
Our 2021 organic capital program will accommodate a net investment level of approximately $65 to $85 million. Our 2021 organic capital program will primarily be focused on affiliate and third-party well connections in the DJ and Delaware Basins. The level of capital spending will be evaluated 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 additional contractual supplier cost savings;
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, and borrowings under our revolving credit facility.
Investment Capital Program
Our 2021 investment capital program will accommodate a net investment level of approximately $15 to $25 million to complete projects at EPIC Crude and EPIC Y-Grade.
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RESULTS OF OPERATIONS
Results of operations were as follows:
 Year Ended December 31,
(in thousands)20202019
Revenues
Midstream Services — Affiliate$389,192 $417,835 
Midstream Services — Third Party94,228 96,194 
Crude Oil Sales — Third Party281,205 189,772 
Total Revenues764,625 703,801 
Costs and Expenses
Cost of Crude Oil Sales270,678 181,390 
Direct Operating92,387 116,675 
Depreciation and Amortization105,697 96,981 
General and Administrative24,721 25,777 
Goodwill Impairment109,734 — 
Other Operating (Income) Expense4,698 (488)
Total Operating Expenses607,915 420,335 
Operating Income156,710 283,466 
Other Expense (Income)
Interest Expense, Net of Amount Capitalized26,570 16,236 
Investment Loss (Income)34,891 17,748 
Total Other Expense (Income)61,461 33,984 
Income Before Income Taxes95,249 249,482 
Tax Provision383 4,015 
Net Income94,866 245,467 
Less: Net Income Prior to the Drop-Down and Simplification— 12,929 
Net Income Subsequent to the Drop-Down and Simplification94,866 232,538 
Less: Net (Loss) Income Attributable to Noncontrolling Interests(39,165)72,542 
Net Income Attributable to Noble Midstream Partners LP$134,031 $159,996 
Adjusted EBITDA (1) Attributable to Noble Midstream Partners LP
$392,926 $254,586 
Distributable Cash Flow (1) of Noble Midstream Partners LP
$326,192 $213,442 
(1)Adjusted EBITDA and Distributable Cash Flow are not measures as determined by 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.
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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,
20202019
DJ Basin
Crude Oil Sales Volumes (Bbl/d)16,964 9,354 
Crude Oil Gathering Volumes (Bbl/d)174,644 182,121 
Natural Gas Gathering Volumes (MMBtu/d)503,794 476,605 
Natural Gas Processing Volumes (MMBtu/d)41,511 50,039 
Produced Water Gathering Volumes (Bbl/d)35,190 39,629 
Fresh Water Delivery Volumes (Bbl/d)91,886 164,524 
Delaware Basin
Crude Oil Gathering Volumes (Bbl/d)54,347 49,842 
Natural Gas Gathering Volumes (MMBtu/d)166,032 155,155 
Produced Water Gathering Volumes (Bbl/d)138,449 148,886 
Total Gathering Systems
Crude Oil Sales Volumes (Bbl/d)16,964 9,354 
Crude Oil Gathering Volumes (Bbl/d)228,991 231,963 
Natural Gas Gathering Volumes (MMBtu/d)669,826 631,760 
Total Barrels of Oil Equivalent (Boe/d) (1)
314,866 322,312 
Natural Gas Processing Volumes (MMBtu/d)41,511 50,039 
Produced Water Gathering Volumes (Bbl/d)173,639 188,515 
Total Fresh Water Delivery
Fresh Water Services Volumes (Bbl/d)91,886 164,524 
(1)Includes crude oil sales volumes that are transported on our gathering systems and sold to third-party customers.
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Revenues
Revenues from our Gathering System and Fresh Water Delivery reportable segments were as follows:
(in thousands)20202019Increase (Decrease)
from Prior Year
Year Ended December 31,
Gathering and Processing — Affiliate$328,411 $337,086 (3)%
Gathering and Processing — Third Party78,654 76,645 %
Fresh Water Delivery Affiliate
57,834 77,566 (25)%
Fresh Water Delivery — Third Party7,680 12,591 (39)%
Crude Oil Sales — Third Party281,205 189,772 48 %
Other — Affiliate2,947 3,183 (7)%
Other — Third Party7,894 6,958 13 %
Total Midstream Services Revenues$764,625 $703,801 %
Revenues Trend Analysis
Revenues increased during 2020 as compared with 2019. The changes in revenues by reportable segment were as follows:
Gathering Systems Gathering Systems revenues increased by $85.5 million during 2020 as compared with 2019 due to the following:
an increase of $91.4 million in crude oil sales due to increased activity associated with the fulfillment of our transportation commitments, which was partially offset by decreased commodity prices during 2020;
an increase of $9.0 million in crude oil 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 Mustang IDP area;
an increase of $5.3 million in crude oil and natural gas gathering services revenues driven by an increase in throughput volumes in the Delaware Basin resulting from an increase in the number of wells connected to our gathering systems;
partially offset by:
a decrease of $12.7 million in crude oil, natural gas and produced water gathering services revenues driven by decreased throughput on our gathering systems resulting from temporary well shut-ins by our customer in the Wells Ranch IDP area; and
a decrease of $5.2 million in crude oil gathering services revenues driven by decreased throughput on our gathering systems resulting from temporary well shut-ins by our customers in the Black Diamond area.
Fresh Water Delivery Fresh Water Delivery revenues decreased by $24.6 million during 2020 as compared with 2019 due to decreased fresh water deliveries in 2020 in the DJ Basin resulting from reduced well completion activity by our customers.
Costs and Expenses
Costs and Expenses Trend Analysis
Costs and expenses were as follows:
(in thousands)
20202019Increase (Decrease)
from Prior Year
Year Ended December 31,
Cost of Crude Oil Sales
$270,678 $181,390 49 %
Direct Operating
92,387 116,675 (21)%
Depreciation and Amortization
105,697 96,981 %
General and Administrative
24,721 25,777 (4)%
Goodwill Impairment109,734 — N/M
Other Operating (Income) Expense
4,698 (488)N/M
Total Operating Expenses
$607,915 $420,335 45 %
N/M Amount is not meaningful
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Cost of Crude Oil Sales Cost of crude oil sales is recorded within our Gathering Systems reportable segment. Cost of crude oil sales increased $89.3 million during 2020 as compared with 2019. The increase was primarily attributable to increased purchases of crude oil to meet our crude oil transportation commitments.
Direct Operating Expenses Direct operating expenses decreased during 2020 as compared with 2019. The changes in direct operating expenses by reportable segment were as follows:
Gathering Systems Gathering Systems direct operating expenses decreased $15.5 million during 2020 as compared with 2019 due to our ability to capture cost efficiencies as well as defer non-essential program work due to COVID-19 and decreased use of third party providers for produced water logistics services resulting from reduced well completion activity and temporary well shut-ins by our customer in the Wells Ranch IDP area.
Fresh Water Delivery Fresh Water Delivery direct operating expenses decreased $10.0 million during 2020 as compared with 2019 primarily due to the decreased use of third-party providers for fresh water logistics services in the DJ Basin resulting from reduced well completion activity by our customers.
Corporate Corporate direct operating expenses increased $1.2 million during 2020 as compared with 2019 primarily due to increased insurance expense.
Depreciation and Amortization Depreciation and amortization expense increased during 2020 as compared with 2019. The changes by reportable segment were as follows:
Gathering Systems Gathering Systems depreciation and amortization expense increased $8.3 million during 2020 as compared with 2019 primarily due to assets placed in service in 2020. 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 assets.
Fresh Water Delivery Fresh Water Delivery depreciation and amortization expense remained consistent during 2020 as compared with 2019 due to our fresh water delivery infrastructure being substantially completed prior to 2019.
General and Administrative Expense General and administrative expense is recorded within our Corporate reportable segment. General and administrative expense decreased $1.1 million during 2020 as compared with 2019. The decrease was primarily attributable to decreased transaction expenses associated with the Drop-Down and Simplification Transaction. The decrease was substantially offset by an increase in the fixed annual fee payable under our omnibus agreement which became effective March 1, 2020. See Item 8. Financial Statements and Supplementary Data – Note 3. Transactions with Affiliates.
Goodwill Impairment During first quarter 2020, we fully impaired our goodwill. See Item 8. Financial Statements and Supplementary Data – Note 2. Summary of Significant Accounting Policies and Basis of Presentation and Management’s Discussion and Analysis of Financial Condition and Results of Operations - Executive Overview and Operating Outlook.
Other Operating Expense (Income) Other operating expense (income) is recorded within our Gathering Systems reportable segment. Other operating expenses during 2020 primarily related to impairments and losses incurred associated with the sale of miscellaneous assets.
Other Expense (Income) Trend Analysis
(in thousands)
20202019Increase (Decrease)
from Prior Year
Year Ended December 31,
Interest Expense$32,030 $33,723 (5)%
Capitalized Interest(5,460)(17,487)(69)%
Interest Expense, Net26,570 16,236 64 %
Investment Loss, Net34,891 17,748 97 %
Total Other Expense, Net$61,461 $33,984 81 %
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, 2020 and 2019 and See Item 8. Financial Statements and Supplementary Data – Note 6. Investments.
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Interest expense decreased $1.7 million during 2020 as compared with 2019. The decrease was primarily due to higher interest rates during 2019, partially offset by higher outstanding long-term balances during 2020.
Capitalized interest decreased $12.0 million during 2020 as compared with 2019. The decrease is primarily attributable to decreased construction-in-progress balances during 2020 as well as no longer capitalizing interest associated with our capital contributions to Delaware Crossing, EPIC Crude and EPIC Y-Grade. As the aforementioned investments have commenced planned, principal operations, we no longer capitalize interest associated with our capital contributions.
Investment Loss, Net Investment loss is recorded within our Investments in Midstream Entities reportable segment and increased $17.1 million during 2020 as compared with 2019. Our Investment loss, net is driven by increased losses from EPIC Crude and EPIC Y-Grade investments. The losses are primarily attributable to expenses incurred prior to commencement and the gradual ramp of throughput volumes. The losses were partially offset by earnings from our investment in Saddlehorn.
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, 2020 and December 31, 2019. 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 15. Income Taxes for a discussion of the changes in our income tax provision and effective tax rates.
Adjusted EBITDA (Non-GAAP Financial Measure)
Adjusted EBITDA should not be considered an alternative to net income, net cash provided by operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Adjusted EBITDA excludes some, but not all, items that affect net income or net cash, and these measures may vary from those of other companies. As a result, our Adjusted EBITDA may not be comparable to similar measures of other companies in our industry.
For a reconciliation of Adjusted EBITDA to its most comparable measures calculated and presented in accordance with GAAP, see Reconciliation of Non-GAAP Financial Measures, below.
We define “Adjusted EBITDA” as net income before income taxes, net interest expense, depreciation and amortization 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.
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 unitholders;
our ability to incur and service debt and fund capital expenditures; and
the viability of acquisitions and other capital expenditure projects and the returns on investment of various investment opportunities.
We believe that the presentation of Adjusted EBITDA provides information useful to investors in assessing our financial condition and results of operations. The GAAP measures most directly comparable to Adjusted EBITDA are net income and net cash provided by operating activities. Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income, net cash provided by operating activities or any other measure as reported in accordance with GAAP.
Distributable Cash Flow (Non-GAAP Financial Measure)
Distributable cash flow should not be considered an alternative to net income, net cash provided by operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Distributable cash flow excludes some, but not all, items that affect net income or net cash provided by operating activities, and these measures may vary from those of other companies. As a result, our distributable cash flow may not be comparable to similar measures of other companies in our industry.
For a reconciliation of distributable cash flow to its most comparable measures calculated and presented in accordance with GAAP, see Reconciliation of Non-GAAP Financial Measures, below.
We define distributable cash flow as Adjusted EBITDA 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.
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Distributable cash flow does not reflect changes in working capital balances. Our partnership agreement requires us to distribute all available cash on a quarterly basis, and distributable cash flow is one of the factors used by the board of directors of our General Partner to help determine the amount of cash that is available to our unitholders for a given period. Therefore, we believe distributable cash flow provides information useful to investors in assessing our financial condition and results of operations. The GAAP measures most directly comparable to distributable cash flow are net income and net cash provided by operating activities. Distributable cash flow should not be considered an alternative to, or more meaningful than, net income, net cash provided by operating activities or any other measure as reported in accordance with GAAP.
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)20202019
Reconciliation from Net Income
Net Income$94,866 $245,467 
Add:
Depreciation and Amortization105,697 96,981 
Interest Expense, Net of Amount Capitalized26,570 16,236 
Proportionate Share of Equity Method Investment EBITDA Adjustments82,363 16,160 
Goodwill Impairment109,734 — 
Other6,531 11,104 
Adjusted EBITDA425,761 385,948 
Less:
Adjusted EBITDA Prior to Drop-Down and Simplification— 26,629 
Adjusted EBITDA Subsequent to Drop-Down and Simplification425,761 359,319 
Less:
Adjusted EBITDA Attributable to Noncontrolling Interests32,835 104,733 
Adjusted EBITDA Attributable to Noble Midstream Partners LP392,926 254,586 
Add:
Distribution from Equity Method Investments Attributable to Noble Midstream Partners LP25,574 10,135 
Less:
Proportionate Share of Equity Method Investment EBITDA Attributable to Noble Midstream Partners LP31,583 (6,275)
Cash Interest Paid31,251 32,984 
Maintenance Capital Expenditures29,474 24,570 
Distributable Cash Flow of Noble Midstream Partners LP$326,192 $213,442 

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Reconciliation of Net Cash Provided by Operating Activities to Adjusted EBITDA and Distributable Cash Flow
Year Ended December 31,
(in thousands)20202019
Reconciliation from Net Cash Provided by Operating Activities
Net Cash Provided by Operating Activities$376,629 $385,143 
Add:
Interest Expense, Net of Amount Capitalized26,570 16,236 
Changes in Operating Assets and Liabilities16,144 (4,165)
Equity Method Investment EBITDA Adjustments7,664 (16,413)
Other(1,246)5,147 
Adjusted EBITDA425,761 385,948 
Less:
Adjusted EBITDA Prior to Drop-Down and Simplification— 26,629 
Adjusted EBITDA Subsequent to Drop-Down and Simplification425,761 359,319 
Less:
Adjusted EBITDA Attributable to Noncontrolling Interests32,835 104,733 
Adjusted EBITDA Attributable to Noble Midstream Partners LP392,926 254,586 
Add:
Distribution from Equity Method Investments Attributable to Noble Midstream Partners LP25,574 10,135 
Less:
Proportionate Share of Equity Method Investment EBITDA Attributable to Noble Midstream Partners LP31,583 (6,275)
Cash Interest Paid31,251 32,984 
Maintenance Capital Expenditures29,474 24,570 
Distributable Cash Flow of Noble Midstream Partners LP$326,192 $213,442 

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 2020, we utilized external financing sources to fund portions of our construction activities and capital contributions to our investments. See Item 8. Financial Statements and Supplementary Data – Note 6. Investments.
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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)20202019
Cash, Cash Equivalents, and Restricted Cash (1)
$16,332 $12,726 
Amount Available to be Borrowed Under Our Revolving Credit Facility (2)
440,000 555,000 
Available Liquidity$456,332 $567,726 
(1)See Item 8. Financial Statements and Supplementary Data – Note 2. Summary of Significant Accounting Policies and Basis of Presentation.
(2)See Item 8. Financial Statements and Supplementary Data – Note 8. Long-Term Debt.
Term Loan Credit Facility Maturity
Our $500 million term loan credit facility matures on July 31, 2021. We are assessing various options and expect to address the maturity prior to July 31, 2021.
Revolving Credit Facility
Our revolving credit facility is available to fund working capital requirements, acquisitions and expansion capital expenditures. In 2020, we utilized our revolving credit facility to fund our capital contributions to Saddlehorn, Delaware Crossing, EPIC Crude, EPIC Y-Grade and EPIC Propane. As of December 31, 2020, $710 million was outstanding under our revolving credit facility. See Item 8. Financial Statements and Supplementary Data – Note 8. Long-Term Debt.
Cash Flows
Summary cash flow information was as follows:
Year Ended December 31,
(in thousands)20202019
Total Cash Provided By (Used in)
Operating Activities$376,629 $385,143 
Investing Activities(427,554)(872,593)
Financing Activities54,531 484,464 
Increase (Decrease) in Cash and Cash Equivalents$3,606 $(2,986)
Operating Activities Net cash provided by operating activities decreased during 2020 as compared with 2019. The decrease was attributable to decreased midstream services revenues resulting from a decrease in throughput volumes, an increase in net interest expense, and changes in working capital. The decrease was partially offset by a decrease in direct operating expenses as well as an increase in distributions from equity method investees.
Investing Activities Cash used in investing activities decreased during 2020 as compared with 2019 primarily due to decreased capital contributions to our equity method investments as well as decreased capital expenditures in 2020. Our decreased capital contributions to Delaware Crossing, EPIC Crude and EPIC Y-Grade were partially offset by our capital contributions to Saddlehorn and EPIC Propane.
Financing Activities Cash provided by financing activities decreased during 2020 as compared with 2019 primarily due to decreases in net long-term borrowings, proceeds from the preferred equity issuance and other equity offerings. The decrease was partially offset by the cash outflow associated with the Drop-Down and Simplification Transaction during 2019 as well as an increase in contributions from noncontrolling interest holders.
Off-Balance Sheet Arrangements
As of December 31, 2020, 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, 2020 that are reflected in the consolidated balance sheets and/or disclosed in the accompanying notes.
Obligation
Note Reference (1)
20212022 and 20232024 and 20252026 and BeyondTotal
(in thousands)
Long-Term Debt (2)
$500,000 $1,110,000 $— $— $1,610,000 
Long-Term Debt Interest Payments and Revolving Credit Facility Commitment Fee (3)
21,512 18,128 — — 39,640 
Asset Retirement Obligations (4)
— — 8,431 33,141 41,572 
Finance Lease Obligations (5)
2,063 — — — 2,063 
Operating Lease Obligations (6)
260 — — — 260 
Purchase Obligations (7)
2,064 — — — 2,064 
Transportation Fees (8)
34,101 69,074