10-K 1 nblx-20171231x10xk.htm 10-K Document

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C.  20549
FORM 10-K
 
ý ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2017
or
o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from          to          
Commission file number: 001-37640
nblxupdatedlogoa28.jpg
NOBLE MIDSTREAM PARTNERS LP
(Exact name of registrant as specified in its charter)
Delaware
 
47-3011449
(State or other jurisdiction of incorporation or organization)
 
(I.R.S. employer identification number)
1001 Noble Energy Way
 
 
Houston, Texas
 
77070
(Address of principal executive offices)
 
(Zip Code)
(281) 872-3100
(Registrant’s telephone number, including area code)
Securities registered pursuant to section 12(b) of the Act:

 
 
 
Title of each class
 
Name of each exchange on which registered
Common Units, Representing Limited Partner Interests
 
New York Stock Exchange
Securities registered pursuant to section 12(g) of the Act: None 
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. ý Yes o No 
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. o Yes ý No 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. ý Yes o No 
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted 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 and post such files). ý Yes o No 
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ý 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See definitions of “large accelerated filer”, “accelerated filer”, “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer ý
Accelerated filer o
Non-accelerated filer o
Smaller reporting company o
Emerging growth company o
 
 
(Do not check if a smaller reporting 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. o
 Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).o Yes ý No
The aggregate market value of the registrant's Common Units held by non-affiliates of the registrant as of June 30, 2017, the last business day of the registrant's most recently completed second fiscal quarter was approximately $813 million.
The registrant had 23,758,442 Common Units and 15,902,584 Subordinated Units outstanding as of February 15, 2018.
DOCUMENTS INCORPORATED BY REFERENCE: None




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.






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 the words “estimate,” “believe,” “budget,” “continue,” “could,” “intend,” “may,” “plan,” “potential,” “predict,” “seek,” “should,” “will,” “would,” “expect,” “objective,” “projection,” “forecast,” “goal,” “guidance,” “outlook,” “effort,” “target,” “on schedule”, “strategy” and other similar expressions that are predictions of or indicate future events and trends and that do not relate to historical matters. Our forward-looking statements may include statements about our business strategy, our industry, our future profitability, our expected capital expenditures and the impact of such expenditures on our performance, the costs of being a publicly traded partnership and our capital programs.
Forward-looking statements are not guarantees of future performance and are based on certain assumptions and bases, and subject to certain risks, uncertainties and other factors, many of which are beyond the Partnership’s control and difficult to predict, and not all of which can be disclosed in advance. We believe that we have chosen these assumptions or bases in good faith and that they are reasonable. You are cautioned not to place undue reliance on any forward-looking statements. You should also understand that it is not possible to predict or identify all such factors and should not consider the following list to be a complete statement of all potential risks and uncertainties. Factors that could cause our actual results to differ materially from the results contemplated by such forward-looking statements include:
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 and natural gas gathering and processing services;
our ability to successfully implement our business plan;
our ability to complete internal growth projects on time and on budget;
the price and availability of debt and equity financing;
the availability and price of crude oil and natural gas to the consumer compared to the price of alternative and competing fuels;
competition from the same and alternative energy sources;
energy efficiency and technology trends;
operating hazards and other risks incidental to our midstream services;
natural disasters, weather-related delays, casualty losses and other matters beyond our control;
interest rates;
labor relations;
defaults by our customers under our gathering and processing agreements;
changes in availability and cost of capital;
changes in our tax status;
the effect of existing and future laws and government regulations;
the effects of future litigation;
interruption of the Partnership’s operations due to social, civil or political events or unrest;
terrorist attacks or cyber threats;
any future acquisitions or dispositions of assets or the delay or failure of any such transaction to close; and
certain factors discussed elsewhere in this Form 10-K. 
You should not place undue reliance on our forward-looking statements. Although forward-looking statements reflect our good faith beliefs at the time they are made, forward-looking statements involve known and unknown risks, uncertainties and other factors, including the factors described under Item 1A. Risk Factors, below, which may cause our actual results, performance or achievements to differ materially from anticipated future results, performance or achievements expressed or implied by such forward-looking statements. We undertake no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events, changed circumstances or otherwise, unless required by law. You should consider carefully the statements under Item 1A. Risk Factors and other sections of this report, which describe factors that could cause our actual results to differ from those set forth in the forward-looking statements.
Unless otherwise stated or the context otherwise indicates, references in this report to “Predecessor,” “we,” “our,” “us” or like terms, when referring to periods prior to September 20, 2016, refer to Noble’s Contributed Businesses (as defined herein), our Predecessor for accounting purposes. All references to “Noble Midstream Partners,” “NBLX,” “the Partnership,” “us,” “our,” “we” or similar expressions, when referring to periods after September 20, 2016, refer to Noble Midstream Partners LP, including its consolidated subsidiaries. References to “Noble” may refer to Noble Energy Inc. and/or its subsidiaries, depending on the context. Our future results of operations may not be comparable to our Predecessor’s historical results of operations. For a summary of commonly used industry terms and abbreviations used in this report, see the Glossary.




PART I

Items 1. and 2. Business and Properties
Overview
We are a growth-oriented Delaware master limited partnership formed in December 2014 by our Parent, Noble, to own, operate, develop and acquire a wide range of domestic midstream infrastructure assets. We currently provide crude oil, natural gas, and water-related midstream services through long-term, fixed-fee contracts. Our current areas of focus are in the Denver-Julesburg Basin in Colorado (DJ Basin) and the Southern Delaware Basin position of the Permian Basin (Delaware Basin) in Texas. The locations of our current areas of focus are shown in the map below:
areaoffocusmapa06.jpg
We are Noble’s primary vehicle for midstream operations in the onshore United States. We have acreage dedications spanning approximately 300,000 acres in the DJ Basin (with over 235,000 dedicated acres from Noble and the remaining dedicated acres from a third party) and approximately 111,000 acres in the Delaware Basin from Noble.
In addition to our existing operations and acreage dedications, Noble has granted us rights of first refusal (ROFRs) on a combination of midstream assets retained, developed or acquired by Noble and services not already dedicated to us in the DJ Basin, Eagle Ford Shale and Delaware Basin, which includes approximately 85,000 additional acres in the DJ Basin, approximately 31,000 acres in the Eagle Ford Shale and approximately 111,000 acres in the Delaware Basin. Noble has also granted us a ROFR on certain onshore United States acreage that may be acquired in the future.
We believe we are well positioned to (i) develop our infrastructure in a manner and on a timeline that will allow us to handle increasing volumes that we anticipate will result from our customer’s 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.
The commercial agreements that we have in place are all fee-based and include dedications of production in the DJ Basin and the Delaware Basin, each with an initial term of 15 years. These long-term, fee-based commercial agreements are intended to mitigate direct commodity price exposure and enhance the stability of our cash flows.
Our business activities are conducted through three operating segments: Gathering Systems (crude oil, natural gas and produced water gathering as well as crude oil treating), Fresh Water Delivery, and Investments and Other.

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Initial Public Offering
On September 20, 2016, we completed our initial public offering (the IPO) of 14,375,000 common units representing limited partner interests in the Partnership (the Common Units), which included 1,875,000 common units issued pursuant to the underwriters’ exercise of their option to purchase additional common units, at a price to the public of $22.50 per Common Unit ($21.20625 per common unit, net of underwriting discounts). In connection with the IPO, Noble contributed to us (i) ownership interests in certain development companies (DevCos) which serve specific areas and integrated development plan (IDP) areas and (ii) a 3.33% ownership interest (the White Cliffs Interest) in White Cliffs Pipeline L.L.C. (White Cliffs). The ownership interests in the DevCos, together with the White Cliffs Interest, are referred to collectively as the Contributed Businesses.
2017 Developments
Advantage Joint Venture
On April 3, 2017, Trinity River DevCo LLC, an indirect wholly owned subsidiary of the Partnership, and Plains Pipeline, L.P. (Plains), a wholly owned subsidiary of Plains All American Pipeline, L.P., completed the acquisition of Advantage Pipeline, L.L.C. (Advantage) for $133 million through a newly formed 50/50 joint venture (the Advantage Joint Venture). Trinity River DevCo LLC contributed $66.8 million of cash in exchange for its 50% interest in the Advantage Joint Venture. We serve as the operator of the Advantage system, which includes a 70-mile crude oil pipeline in the Southern Delaware Basin from Reeves County, Texas to Crane County, Texas, with 150,000 barrels of daily shipping capacity and 490,000 barrels of storage capacity. We use the equity method of accounting for our investment in the Advantage Joint Venture, as we do not control, but do exert significant influence over, its operations. The Partnership funded the acquisition with a combination of borrowings under our revolving credit facility and from cash on hand.
Dedication and ROFR Update
On April 24, 2017, Noble completed the acquisition of Clayton Williams Energy, Inc. Upon closing of the acquisition, approximately 64,000 net acres in the Delaware Basin were dedicated to us for infield crude oil, natural gas, and produced water gathering. We have a ROFR to provide services for the remaining acreage acquired by Noble. Additionally, an infield natural gas gathering dedication was added to the existing crude oil and produced water gathering dedication on substantially all of Noble’s legacy 47,000 Delaware Basin net acres. Both acreage dedications are held by the Blanco River DevCo LP. In conjunction with the new dedications, we waived our ROFR for natural gas processing on approximately 80,000 net acres in the Delaware Basin, of which approximately 35,000 net acres were dedicated to a third party through 2021.
Contribution Agreement
On June 20, 2017, the Partnership entered into a Contribution Agreement (the Contribution Agreement) by and among the Partnership, Noble Midstream GP LLC, our general partner, Noble Midstream Services, LLC (Midstream Services), NBL Midstream, LLC (NBL Midstream), a subsidiary of Noble, and Blanco River DevCo GP LLC (Blanco River DevCo GP). Pursuant to the terms of the Contribution Agreement, the Partnership agreed to acquire from NBL Midstream (i) the remaining 20% limited partner interest in Colorado River DevCo LP and (ii) an additional 15% limited partner interest in Blanco River DevCo LP (collectively, the Contributed Assets). In consideration for the Contributed Assets, the Partnership agreed to pay NBL Midstream $270 million, consisting of (i) $245 million in cash and (ii) 562,430 Common Units issued to NBL Midstream at an issue price of $44.45 per Common Unit, the closing price of our Common Units on the New York Stock Exchange (the NYSE) on June 20, 2017 (the Transaction). The Transaction closed on June 26, 2017. The Partnership funded the cash consideration with a combination of borrowings under our revolving credit facility, proceeds from the Private Placement (as defined below), and cash on hand.
Private Placement
On June 20, 2017, the Partnership entered into a Common Unit Purchase Agreement with certain institutional investors, pursuant to which the Partnership agreed to sell 3,525,000 Common Units in a private placement for gross proceeds of approximately $142.6 million (the Private Placement). Net proceeds totaled approximately $138.0 million, after deducting offering expenses of approximately $4.6 million. The Private Placement closed on June 26, 2017.
Black Diamond Gathering LLC
On December 12, 2017, Black Diamond Gathering LLC (Black Diamond), an entity formed by Black Diamond Gathering Holdings LLC (the Noble Member), a wholly-owned subsidiary of the Partnership, and Greenfield Midstream, LLC, an EnCap Flatrock Midstream portfolio company (the Greenfield Member), entered into a Membership Interest Purchase and Sale Agreement (the Acquisition Agreement) with Saddle Butte Pipeline II, LLC (Seller), pursuant to which Black Diamond agreed to acquire all of the issued and outstanding limited liability company interests (the Acquisition) in Saddle Butte Rockies Midstream, LLC and certain affiliates (collectively, Saddle Butte). We will serve as the operator of the Saddle Butte system which includes a large-scale integrated gathering system located in the core of the DJ Basin with approximately 160 miles of

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pipeline in operation and delivery capacity of approximately 300 MBbl/d. Saddle Butte has approximately 141,000 dedicated acres from six customers under fixed fee arrangements.
On January 31, 2018, Black Diamond closed the Acquisition for approximately $638.5 million, which included certain pre-closing adjustments made in proportion to each party’s respective equity ownership interest, and which are subject to customary final adjustments following closing. In accordance with the Black Diamond Gathering LLC Agreement, Noble Member received a 54.4% equity ownership interest in Black Diamond. The Partnership funded its share of the purchase price (approximately $319.9 million) through a combination of cash on hand, proceeds from the Unit Offering (defined below) and borrowings under its revolving credit facility. See Item 8. Financial Statements and Supplementary Data – Note 14. Subsequent Events.
Unit Offering
On December 12, 2017, the Partnership entered into an Underwriting Agreement providing for the offer and sale of 3,680,000 Common Units (including 480,000 Common Units issued pursuant to the underwriters’ option to purchase additional Common Units, at a price of $47.50 per Common Unit) (the Unit Offering).  Net proceeds totaled approximately $174.1 million, after deducting offering expenses of approximately $0.7 million. The Unit Offering closed on December 15, 2017. Proceeds from the Unit Offering were used to repay outstanding borrowings under our revolving credit facility and fund our share of the purchase price for the Acquisition.


5


Organizational Structure
DevCo Ownership Interests
Our DevCo structure provides multiple avenues for organic and drop down growth. The following table provides a summary of our assets, services and dedicated net acreage, along with our ownership of these assets, as of December 31, 2017:
DevCo
NBLX Ownership
Areas Served
NBLX Dedicated Service
Current Status of Asset
Dedicated Net Acreage
Colorado River DevCo LP
100%

Wells Ranch IDP (DJ Basin)


East Pony (DJ Basin)

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

Crude Oil Gathering

Crude Oil Treating

Operational


Operational

Operational

78,000


44,000

N/A(1)
San Juan River DevCo LP
25%
East Pony IDP (DJ Basin)
Water Services
Operational
44,000
Green River DevCo LP
25%
Mustang IDP (DJ Basin)(2)
Crude Oil Gathering
Natural Gas Gathering
Water Services
Planning
Planning
Partially Operational
75,000
Laramie River DevCo LP
100%
Greeley Crescent IDP (DJ Basin)(3)
Crude Oil Gathering
Water Services
Operational
65,000(3) (4)
Blanco River DevCo LP
40%
Delaware Basin
Crude Oil Gathering
Natural Gas Gathering
Water Services
Operational
111,000(5)
Gunnison River DevCo LP
5%
Bronco IDP (DJ Basin)(6)
Crude Oil Gathering
Water Services
Future Development
36,000(4)
Trinity River DevCo LLC(7)
100%
Delaware Basin
Gas Compression
Crude Oil Transmission(7)
Operational
111,000(5)
(1) 
The fee for crude oil treating services is not acreage based. We receive a monthly fee for each Noble-operated well producing in paying quantities in the DJ Basin that is not connected to our crude oil gathering systems during each month, which was 2,224 wells as of December 31, 2017.
(2) 
We currently have limited midstream infrastructure assets in the Mustang IDP area of the DJ Basin (Mustang IDP). Our assets in the Mustang IDP currently consists primarily of dedications to us from Noble for future production. In the Mustang IDP, we own one fresh water storage pond with a storage capacity of approximately 230,000 Bbls of water, rights-of-way and surface rights on which we are constructing additional components of the fresh water system and on which we plan to construct crude oil, natural gas and water infrastructure in order to provide services under our dedications. We anticipate the first centralized facility servicing the Mustang IDP and related gathering infrastructure to be in service by the end of first quarter 2018.
(3) 
Our assets in the Greeley Crescent IDP area of the DJ Basin (Greeley Crescent IDP) currently consist of dedications to us from Noble and an unaffiliated third party. During 2017, Noble closed the sale of approximately 33,100 net acres in the Greeley Crescent IDP to such third party. All of the acreage in the Greeley Crescent IDP remains subject to the dedications in favor of us for crude oil gathering, produced water services and fresh water services.
(4) 
During 2017, Noble entered into an agreement to sell approximately 30,200 net acres across the Greeley Crescent IDP and the Bronco IDP area of the DJ Basin (Bronco IDP) to an unaffiliated third party. The first closing in respect of such sale, pursuant to which the acreage and non-operated production was conveyed from Noble, occurred in 2017. A second closing for operated producing properties is expected to occur in mid-2018. All of the acreage remains subject to the dedications in favor of us for crude oil gathering, produced water services and fresh water services.
(5) 
Upon closing of the Clayton Williams Energy, Inc. acquisition by Noble, approximately 64,000 net acres in the Delaware Basin were dedicated to us for infield crude oil, natural gas, and produced water gathering. Additionally, an infield natural gas gathering dedication was added to the existing crude oil and produced water gathering dedication on substantially all of Noble’s legacy 47,000 Delaware Basin net acres.
(6) 
We currently have no midstream infrastructure assets in the Bronco IDP. Our assets in the Bronco IDP currently consist primarily of dedications to us from Noble for future production in this IDP area.
(7) 
Trinity River DevCo LLC owns a 50% ownership interest in the Advantage Joint Venture. Crude oil produced from Noble’s legacy 47,000 Delaware Basin net acres is dedicated to the Advantage system.

6


Investments
We own a 3.33% ownership interest in White Cliffs. The White Cliffs pipeline system (the White Cliffs Pipeline) consists of two 527-mile crude oil pipelines that extend from the DJ Basin to Cushing, Oklahoma, with a capacity of approximately 215,000 Bbl/d.
We own a 50% ownership interest in the Advantage Joint Venture. We serve as the operator of the Advantage system, which includes a 70-mile crude oil pipeline in the Southern Delaware Basin from Reeves County, Texas to Crane County, Texas, with a capacity of 150,000 Bbl/d and 490,000 barrels of storage capacity.
Rights of First Refusal (ROFR)
Noble has granted us a ROFR on the right to provide midstream services on certain acreage described below and on the right to acquire certain midstream assets. The following table provides a summary of the ROFR assets and ROFR services granted to us by Noble as well as the net acreage covered by our ROFR, to the extent known as of December 31, 2017, granted to us by Noble.
Areas Served
NBLX ROFR Service
Current Status of Asset
ROFR Net Acreage
East Pony (Northern Colorado)
Natural Gas Processing
Natural Gas Gathering
Operational
44,000
Eagle Ford Shale
Crude Oil Gathering
Natural Gas Gathering
Water Services
Operational
31,000
DJ Basin (other than dedicated above)
To the extent not already covered in dedication in the prior chart:

Crude Oil Gathering
Natural Gas Gathering
Water Services
N/A
85,000
Delaware Basin
Water Services
In Progress
111,000
All future-acquired onshore acreage in the United States (outside of the Marcellus Shale)
Crude Oil Gathering
Natural Gas Gathering
Natural Gas Processing
Water Services
N/A
N/A
Rights of First Offer (ROFO)
Noble has granted us a ROFO with respect to its retained interests in the DevCos through which we conduct our midstream services. Pursuant to our ROFO, before Noble can offer any of its retained interests in the DevCos to any third party, Noble must allow us to make an offer to purchase these interests. We believe that the ROFO on Noble’s retained interests in our DevCos will provide us an opportunity to develop organic growth with potentially lower development capital costs. We are under no obligation to purchase any of Noble’s retained interests in the DevCos, and Noble is only under an obligation to permit us to make an offer on these interests to the extent that Noble elects to sell these midstream assets to a third party.


7


Organizational Structure
The following diagram depicts our organizational structure as of December 31, 2017. DevCos identified in red and blue indicate the location of the assets in the DJ Basin or Delaware Basin, respectively.

orgstructure2017a04.jpg


8


Our Relationship with Noble
One of our principal strengths is our relationship with Noble. Given Noble’s significant ownership interest in us and its intent to use us as its primary domestic midstream service provider in areas that have not previously been dedicated to other ventures, we believe that Noble will be incentivized to promote and support the successful execution of our business strategies; however, we can provide no assurances that we will benefit from our relationship with Noble. While our relationship with Noble is a significant strength, it is also a source of potential risks and conflicts. Noble accounts for a substantial portion of our revenues. It is the only customer that accounts for more than 10% of our revenues and the loss of Noble as a customer would have a material adverse effect on us. See Item 1A. Risk Factors.
Business Strategies
Our principal business objectives are as follows:
Ensuring the ongoing stability of our business by providing outstanding service to our upstream customers; and
Generating stable cash flows, providing for potential future increases in quarterly cash distributions paid to our unitholders over time.
We expect to achieve these objectives through the following business strategies:
Acting as the primary provider of midstream services in Noble’s dedicated areas. We are strategically positioned to expand our delivery of midstream services within the areas dedicated to us as Noble executes on its drilling and development plans.
Pursuing accretive acquisitions from Noble and third parties. We believe Noble is strongly incentivized to help us grow our business. This includes offering us the opportunity to acquire midstream assets it has retained, develops or acquires in the future and elects to sell. Additionally, we believe that we are positioned to pursue acquisitions from third parties.
Attracting additional third party business. We believe that our portfolio of assets and our execution and operational capabilities will position us favorably to compete for additional third party production.
Focusing on long-term, fixed-fee arrangements to mitigate direct commodity price exposure and enhance the stability of our cash flows. We pursue additional long-term commitments from customers, which may include acreage dedications, throughput-based charges, or reservation-based charges. None of our existing commercial agreements contain minimum volume commitments.
Competitive Strengths
We believe we are well-positioned to successfully execute our business strategies because of the following competitive strengths:
Strong relationship with Noble. We believe Noble will be incentivized to promote and support our business plan and to pursue projects that enhance the overall value of our business. We believe that our relationship with Noble will provide us with a stable base of cash flows and significant growth opportunities.
Strategically located assets. We believe that our existing footprint, coupled with our long-term dedications, positions us to capitalize on midstream growth opportunities on and around our customers’ contiguous acreage in the DJ Basin and Delaware Basin.
Long-term, fixed-fee contracts to support cash flows. We believe that Noble’s horizontal drilling activity and potential new third party customers will drive the stable growth of our midstream operations. Our contract structure mitigates our direct exposure to commodity price risk and will likely contribute to long-term cash flow stability.
Financial flexibility and strong capital structure. We believe that our available borrowing capacity and our ability to access debt and equity capital markets provide us with the financial flexibility necessary to execute our business and growth strategies.
Experienced management and operating teams. Our executive management team has combined experience of approximately 60 years in designing, acquiring, building, operating, financing and otherwise managing large-scale midstream and other energy assets. In addition, through our omnibus agreement and operational services and secondment agreement with Noble, we employ engineering, construction and operations teams that have significant experience in designing, constructing and operating large scale midstream and other energy assets.



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Areas of Operation
The following diagram illustrates our areas of operations as of December 31, 2017:

areasoffocusa01.jpg

10


Reportable Segments
We manage our operations by the nature of the services we offer. Our reportable segments comprise the structure used to make key operating decisions and assess performance. We are organized into the following reportable segments: Gathering Systems (crude oil, natural gas and produced water gathering as well as crude oil treating), Fresh Water Delivery, and Investments and Other. We often refer to services of our Gathering Systems and Fresh Water Delivery segments collectively as our midstream services. The Investments and Other segment includes our investments in the Advantage Joint Venture and White Cliffs Interest as well as all general Partnership activity not attributable to our DevCos. See Item 8. Financial Statements and Supplementary Data – Note 8. Segment Information.
Gathering Systems
Crude Oil Gathering
Our crude oil gathering systems in the DJ Basin include approximately 142 miles of pipeline, 66 miles of which service the Wells Ranch IDP area of the DJ Basin (the Wells Ranch IDP). Our crude oil gathering assets also include 96,000 Bbls of storage capacity at the Wells Ranch Central Gathering Facility (CGF) where we are able to recover gas vapors from the crude oil and deliver this natural gas to Noble for delivery to downstream third parties. The 66 miles of pipeline in the Wells Ranch IDP area are shared crude oil and produced water gathering pipelines.
To service the East Pony IDP area of the DJ Basin (the East Pony IDP), we gather crude oil meeting pipeline specifications and deliver it through approximately 34 miles of pipeline directly into the northern extension of the Wattenberg Oil Trunkline and the Northeast Colorado Lateral of the Pony Express Pipeline. Crude oil gathering of production from the East Pony IDP area is subject to Federal Energy Regulatory Commission (FERC) jurisdiction. See Regulation of Operations. We began gathering crude oil in our system in March 2015.
To service the Greeley Crescent IDP, we gather crude oil meeting pipeline specifications for an unaffiliated third party. We deliver the gathered crude oil through approximately 42 miles of pipeline directly into the Grand Mesa pipeline and White Cliffs Pipeline. We began gathering crude oil in the Greeley Crescent IDP area in the third quarter of 2017.
Our crude oil gathering systems in the Delaware Basin include approximately 59 miles of pipeline. We gather off-spec crude oil from well pad facilities, which is delivered to various CGFs. The CGFs will stabilize the crude to be sent downstream to pipelines leaving the Delaware Basin. We began gathering crude oil in the Delaware Basin during the third quarter of 2017.
The table below sets forth our crude oil gathering capacity and operations as of and for the dates indicated.
 
Throughput Capacity (Bbl/d)
 
Average Daily Throughput (Bbl/d)
 
Number of Horizontal Wells
 
As of December 31,
 
Year Ended December 31,
 
As of December 31,
 
2017
 
2016
 
2017
 
2016
 
2017
 
2016
Wells Ranch IDP
50,000

 
45,000

 
33,703

 
26,802

 
407

 
356

East Pony IDP
85,000

 
85,000

 
22,828

 
18,434

 
249

 
200

Greeley Crescent IDP
60,000

 

 
5,333

 

 
60

 

Delaware Basin
30,000

 

 
3,791

 

 
19

 

(1) 
Each of our CGFs in the Delaware Basin, Billy Miner I and Jesse James, have a throughput capacity of 15,000 Bbl/d.

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Crude Oil Treating
We also operate two crude oil treating facilities, the Platteville and the Briggsdale facilities. These facilities service each of the IDP areas and additional wells outside of these areas. The permits under which we operate the Platteville and Briggsdale facilities permit approximately 1,825,000 Bbls and 2,740,000 Bbls, respectively, of crude oil to be treated during each year. Crude oil is delivered to the facilities by truck. If treatment is required, the crude oil is directed to, and received by, the treating facility to process the crude oil to meet pipeline specification. For access to and the services provided at the crude oil treating facilities, Noble pays monthly fees based on the number of producing vertical and horizontal wells located in the DJ Basin that are not connected to our gathering system, whether such wells fall within or outside of an IDP area.
The below sets forth the number of producing vertical and horizontal wells in the DJ Basin that are not connected to our gathering system and are subject to a monthly fee as of the dates indicated.
 
Number of Wells Subject to Monthly Fee
 
As of December 31, 2017
 
As of December 31, 2016
Producing Vertical Wells
1,753

 
3,016

Producing Horizontal Wells
471

 
515

Natural Gas Gathering
Our natural gas infrastructure assets in the DJ Basin consist of the Wells Ranch CGF and an approximately 58-mile natural gas pipeline system servicing production from the Wells Ranch IDP. The natural gas gathering system that services the production from the Wells Ranch IDP collects gas from separator facilities located at or near the wellhead and delivers the gas to the Wells Ranch CGF or other delivery points within the Wells Ranch IDP. At the tailgate of our natural gas gathering facilities or the Wells Ranch CGF or other delivery points, as applicable, we deliver the natural gas for further processing by third parties.
Our natural gas infrastructure assets in the Delaware Basin consist of the Billy Miner I and Jesse James CGFs as well as an approximately 59-mile natural gas pipeline system servicing production from the Delaware Basin. The natural gas gathering system that services the production from the Delaware Basin collects gas from the wellhead off of a high pressure separator and sends it to various CGFs. The CGFs dehydrate the gas, compress it, and send it downstream for processing.
The table below sets forth our natural gas gathering capacity and operations as of and for the dates indicated.
 
Throughput Capacity (Mcf/d)
 
Average Daily Throughput (MMBtu/d)
 
Number of Horizontal Wells
 
As of December 31,
 
Year Ended December 31,
 
As of December 31,
 
2017
 
2016
 
2017
 
2016
 
2017
 
2016
Wells Ranch IDP
150,000

 
150,000

 
172,284

 
132,147

 
426

 
375

Delaware Basin (1)
60,000

 

 
8,634

 

 
19

 

(1) 
Each of our CGFs in the Delaware Basin, Billy Miner I and Jesse James, have a throughput capacity of 30,000 Mcf/d.
Our Wells Ranch CGF provides condensate separation and flash gas recovery. Condensate recovered from the natural gas that is gathered to the Wells Ranch CGF is stored on location and gas that is flashed from the crude oil is recovered, compressed and redelivered to downstream third parties with the gathered natural gas volumes.
Produced Water Gathering
Our produced water gathering system in the Wells Ranch IDP gathers and processes liquids produced from operations and consists of a combination of separation and storage facilities, and permanent pipelines, as well as pumps to transport produced water to disposal facilities. We operate an approximately 66-mile gathering pipeline system (which is a shared crude oil and produced water gathering pipeline) servicing the Wells Ranch IDP. Crude oil and produced water are separated and measured at facilities at or near the wellhead and recombined and delivered into our gathering system. At the Wells Ranch CGF, the incoming crude oil and produced water liquid stream is separated, stored, and treated before the crude oil is delivered to a third party pipeline. The Wells Ranch CGF has the capacity to store up to 32,000 Bbls of produced water while awaiting delivery to a disposal facility.
Our produced water gathering system in the Greeley Crescent IDP gathers liquids produced from operations and consists of a combination of pumps and permanent pipelines to transport produced water to disposal facilities. We operate an approximately 20-mile gathering pipeline system servicing the Greeley Crescent IDP.

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Our produced water gathering system in the Delaware Basin gathers and processes liquids produced from operations and consists of stabilization facilities, and permanent pipelines, as well as pumps to transport produced water to disposal facilities. We operate an approximately 67-mile gathering pipeline system servicing the Delaware Basin. At our CGFs, the incoming produced water is skimmed and pumped downstream to the disposal wells. Our CGFs have the capacity to process up to 30,000 Bbls of produced water and transport it to a disposal facility.
We enter into and manage contracts with third party providers of any produced water services that we do not perform ourselves.
The table below sets forth our produced water capacity and operations as of and for the dates indicated.
 
Throughput Capacity (Bbl/d)
 
Average Daily Throughput (Bbl/d)
 
Number of Horizontal Wells
 
As of December 31,
 
Year Ended December 31,
 
As of December 31,
 
2017
 
2016
 
2017
 
2016
 
2017
 
2016
Wells Ranch IDP
30,000

 
15,000

 
14,097

 
10,592

 
407

 
5,661

Greeley Crescent IDP
20,000

 

 
2,338

 

 
60

 

Delaware Basin (1)
60,000

 

 
7,996

 

 
19

 

(1) 
Each of our CGFs in the Delaware Basin, Billy Miner I and Jesse James, have a throughput capacity of 30,000 Bbl/d.
Fresh Water Delivery
Our fresh water systems provide services for both treated produced water and raw fresh water that has been withdrawn from a river or ground water, for example. Our fresh water services include distribution and storage services that are integral to Noble’s drilling and completion operations.
Our fresh water systems in the DJ Basin contain an approximately 55-mile fresh water distribution system made up of permanent buried pipelines, 9 miles of which service the East Pony IDP, 22 miles of which service the Wells Ranch IDP, 12 miles which service the Mustang IDP, and 12 miles of which serve the Greeley Crescent IDP. In addition, our fresh water systems include fresh water storage facilities in the Wells Ranch IDP, East Pony IDP and Mustang IDP, as well as temporary pipelines and pumping stations to transport fresh water throughout the pipeline networks. These systems are designed to deliver water on demand to hydraulic fracturing operations and reduce the costs of transporting water long distances by reducing or eliminating most trucking costs. The fresh water systems provide storage capacity that segregates raw fresh water from produced water that has been treated.
We do not own or hold title to the water nor do we own or operate fresh water sources, but instead our services are focused on the storage and distribution of the fresh water delivered to us by our customers.
The table below sets forth our fresh water delivery services capacity and operations as of and for the dates indicated.
 
Distribution Capacity (Bpm)
 
Average Daily Throughput (Bbl/d)
 
Storage Capacity (Bbls)
 
As of December 31,
 
Year Ended December 31,
 
As of December 31,
 
2017
 
2016
 
2017
 
2016
 
2017
 
2016
Wells Ranch IDP
160

 
160

 
83,856

 
64,306

 
500,000

 
500,000

East Pony IDP
160

 
160

 
34,676

 
22,423

 
550,000

 
550,000

Mustang IDP (1)
160

 
160

 

 
7,498

 
1,180,000

 
230,000

Greeley Crescent IDP
160

 

 
37,458

 

 

 

(1) 
Consists of a system delivering fresh water from Noble-owned water wells to storage ponds. A volumetric fee for the fresh water distributed from this pond is charged as the water is distributed from the pond by truck or third party temporary pipeline. During 2017, no fresh water was delivered due to the timing of well completion activity by Noble.
Investments and Other
Our Investments and Other segment includes our investments in the Advantage Joint Venture and White Cliffs Interest as well as all general Partnership activity not attributable to our DevCos.
We own a 3.33% ownership interest in White Cliffs. The White Cliffs Pipeline consists of two 527-mile crude oil pipelines that extend from the DJ Basin to Cushing, Oklahoma, with a capacity of approximately 215,000 Bbl/d.

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We own a 50% ownership interest in the Advantage Joint Venture. We serve as the operator of the Advantage system, which includes a 70-mile crude oil pipeline in the Southern Delaware Basin from Reeves County, Texas to Crane County, Texas, with a capacity of 150 MBbl/d and 490,000 barrels of storage capacity. Crude oil throughput volumes during 2017 averaged 44 MBbl/d.

Regulation of Operations
The midstream services we provide are subject to regulations that may affect certain aspects of our business and the market for our services.
Safety and Maintenance Regulation
We are subject to regulation by the United States Department of Transportation, or DOT, under the Hazardous Liquids Pipeline Safety Act of 1979, or HLPSA, and comparable state statutes with respect to design, installation, testing, construction, operation, replacement and management of pipeline facilities. HLPSA covers petroleum and petroleum products, including NGLs and condensate, and requires any entity that owns or operates pipeline facilities to comply with such regulations, to permit access to and copying of records and to file certain reports and provide information as required by the United States Secretary of Transportation. These regulations include potential fines and penalties for violations.
We are also subject to the Natural Gas Pipeline Safety Act of 1968, or NGPSA, and the Pipeline Safety Improvement Act of 2002. The NGPSA regulates safety requirements in the design, construction, operation and maintenance of natural gas pipeline facilities while the Pipeline Safety Improvement Act of 2002 establishes mandatory inspections for all United States crude oil and natural gas transportation pipelines and some gathering pipelines in high-consequence areas within ten years. DOT, through the Pipeline and Hazardous Materials Safety Administration, or PHMSA, has developed regulations implementing the Pipeline Safety Improvement Act of 2002 that requires pipeline operators to implement integrity management programs, including more frequent inspections and other safety protections in areas where the consequences of potential pipeline accidents pose the greatest risk to people and their property.
The Pipeline Safety and Job Creations Act, enacted in 2012, amended the HLPSA and NGPSA and increased safety regulation. This legislation doubles the maximum administrative fines for safety violations from $100,000 to $200,000 for a single violation and from $1.0 million to $2.0 million for a related series of violations, and provides that these maximum penalty caps do not apply to civil enforcement actions, establishes additional safety requirements for newly constructed pipelines, and requires studies of certain safety issues that could result in the adoption of new regulatory requirements for existing pipelines, including the expansion of integrity management, use of automatic and remote-controlled shut-off valves, leak detection systems, sufficiency of existing regulation of gathering pipelines, use of excess flow valves, verification of maximum allowable operating pressure, incident notification, and other pipeline-safety related requirements. PHMSA has undertaken rulemaking to address many areas of this legislation.
In addition, in May 2016, PHMSA proposed rules that would, if adopted, impose more stringent requirements for certain natural gas lines. Among other things, the proposed rulemaking would extend certain of PHMSA’s current regulatory safety programs for gas pipelines beyond ‘‘high consequence areas’’ to cover gas pipelines found in newly defined ‘‘moderate consequence areas’’ that contain as few as five dwellings within the potential impact area and would also require gas pipelines installed before 1970 that are currently exempted from certain pressure testing obligations to be tested to determine their maximum allowable operating pressures, or MAOP. Other new requirements proposed by PHMSA under rulemaking would require pipeline operators to: report to PHMSA in the event of certain MAOP exceedances; strengthen PHMSA integrity management requirements; consider seismicity in evaluating threats to a pipeline; conduct hydrostatic testing for all pipeline segments manufactured using longitudinal seam welds; and use more detailed guidance from PHMSA in the selection of assessment methods to inspect pipelines. The proposed rulemaking also seeks to impose a number of requirements on natural gas gathering lines. Issuance of the final rule remains pending. More recently, in January 2017, PHMSA finalized regulations for hazardous liquid pipelines that significantly extend and expand the reach of certain PHMSA integrity management requirements (i.e., periodic assessments, leak detection and repairs), regardless of the pipeline’s proximity to a high consequence area. The final rule would also impose new reporting requirements for certain unregulated pipelines, including all hazardous liquid gathering lines. However, PHMSA has delayed publication of the January 2017 rule in the federal register and, as a result, the rule has not yet become effective. Extending the integrity management requirements to our gathering pipelines would impose additional obligations on us and could add material cost to our operations. In addition, any material penalties or fines issued to us under these or other statutes, rules, regulations or orders could have an adverse impact on our business, financial condition, results of operation and cash flows.
States are largely preempted by federal law from regulating pipeline safety but may assume responsibility for enforcing intrastate pipeline regulations at least as stringent as the federal standards. The Colorado Public Utilities Commission is the agency vested with intrastate natural gas pipeline regulatory and enforcement authority in Colorado. The Colorado Public

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Utilities Commission’s regulations adopt by reference the minimum federal safety standards for the transportation of natural gas. We do not anticipate any significant problems in complying with applicable federal and state laws and regulations in Colorado. Our natural gas transmission and regulated gathering pipelines have ongoing inspection and compliance programs designed to keep the facilities in compliance with pipeline safety and pollution control requirements.
In addition, we are subject to the requirements of the federal Occupational Safety and Health Act, or OSHA, and comparable state statutes, whose purpose is to protect the health and safety of workers, both generally and within the pipeline industry. Moreover, the OSHA hazard communication standard, the Environmental Protection Agency, or EPA, community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We and the entities in which we own an interest are also subject to OSHA process safety management regulations, which are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals. These regulations apply to any process which involves a chemical at or above specified thresholds, or any process which involves flammable liquid or gas, pressurized tanks, caverns and wells in excess of 10,000 pounds at various locations. Flammable liquids stored in atmospheric tanks below their normal boiling point without the benefit of chilling or refrigeration are exempt from these standards. Also, the Department of Homeland Security and other agencies such as the EPA continue to develop regulations concerning the security of industrial facilities, including crude oil and natural gas facilities. We are subject to a number of requirements and must prepare federal response plans to comply. We must also prepare risk management plans under the regulations promulgated by the EPA to implement the requirements under the Clean Air Act, or CAA, to prevent the accidental release of extremely hazardous substances. The EPA finalized revisions to its Risk Management Program, or RMP, rules in January 2017. The final rules include requirements to: (i) complete third-party audits of an RMP program following an accident; (ii) consider inherently safer technology during process hazard assessments; (iii) conduct root cause analysis assessing how management failures lead to the incident; (iv) take corrective actions for the root cause identified; and (v) impose broad information-sharing requirements with emergency planners and the public and require joint emergency response exercises with local responders. In June 2017, the EPA issued a stay of the revised RMP requirements until 2019, which was immediately challenged by environmental groups. A final decision remains pending. However, pursuant to the January 2017 rulemaking, many of the revised requirements do not come become effective until 2021. We have an internal program of inspection designed to monitor and enforce compliance with safeguard and security requirements.
FERC and State Regulation of Natural Gas and Crude Oil Pipelines
The FERC’s regulation of crude oil and natural gas pipeline transportation services and natural gas sales in interstate commerce affects certain aspects of our business and the market for our products and services.
Natural Gas Gathering Pipeline Regulation
Section 1(b) of the Natural Gas Act of 1938, or NGA, exempts natural gas gathering facilities from the jurisdiction of the FERC under the NGA. We believe that our natural gas gathering facilities meet the traditional tests the FERC has used to establish a pipeline’s status as a gathering pipeline and therefore our natural gas gathering facilities should not be subject to FERC jurisdiction. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services has been the subject of frequent litigation and varying interpretations and the FERC determines whether facilities are gathering facilities on a case by case basis, so the classification and regulation of our gathering facilities may be subject to change based on future determinations by the FERC, the courts, or Congress. If the FERC were to determine that all or some of our gathering facilities or the services provided by us are not exempt from FERC regulation, the rates for, and terms and conditions of, services provided by such facilities would be subject to regulation by the FERC, which could in turn decrease revenue, increase operating costs, and, depending upon the facility in question, adversely affect our results of operations and cash flows.
The Energy Policy Act of 2005, or EPAct 2005, amended the NGA to add an anti-market manipulation provision. Pursuant to the FERC’s rules promulgated under EPAct 2005, it is unlawful for any entity, directly or indirectly, in connection with the purchase or sale of natural gas subject to the jurisdiction of the FERC, or the purchase or sale of transportation services subject to FERC jurisdiction: (1) to use or employ any device, scheme or artifice to defraud; (2) to make any untrue statement of material fact or omit a material fact; or (3) to engage in any act or practice that operates as a fraud or deceit upon any person. EPAct 2005 provided the FERC with substantial enforcement authority, including the power to assess civil penalties of up to $1,238,271 per day per violation, to order disgorgement of profits and to recommend criminal penalties. Failure to comply with the NGA, EPAct 2005 and the other federal laws and regulations governing our business can result in the imposition of administrative, civil and criminal remedies.
Colorado regulation of gathering facilities includes various safety, environmental and ratable take requirements. Our purchasing, gathering and intrastate transportation operations are subject to Colorado’s ratable take statute, which provides that each person purchasing or taking for transportation crude oil or natural gas from any owner or producer shall purchase or take

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ratably, without discrimination in favor of any owner or producer over any other owner or producer in the same common source of supply offering to sell his crude oil or natural gas produced therefrom to such person. This statute has the effect of restricting our right as an owner of gathering facilities to decide with whom we contract to transport natural gas. The ratable take statute is in the enabling legislation of the Colorado Oil and Gas Conservation Commission, or the COGCC.
The COGCC regulations require operators of natural gas gathering lines to file several forms and provide financial assurance, and they also impose certain requirements on gathering system waste. Moreover, the COGCC probably retains authority to regulate the installation, reclamation, operation, maintenance, and repair of gathering systems should the agency choose to do so. Should the COGCC exercise this authority, the consequences for the Partnership will depend upon the extent to which the authority is exercised. We cannot predict what effect, if any, the exercise of such authority might have on our operations.
Our natural gas gathering facilities are not subject to rate regulation or open access requirements by the Colorado Public Utilities Commission. However, the Colorado Public Utilities Commission requires us to register as pipeline operators, pay assessment and registration fees, undergo inspections and report annually on the miles of pipeline we operate.
Many of the producing states have adopted some form of complaint-based regulation that generally allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to natural gas gathering access and rate discrimination. Although Colorado does not have complaint-based regulation, additional rules and legislation pertaining to these matters are considered or adopted from time to time. We cannot predict what effect, if any, such changes might have on our operations, but we could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.
Crude Oil Pipeline Regulation
Pipelines that transport crude oil in interstate commerce are subject to regulation by the FERC pursuant to the Interstate Commerce Act, or ICA, the Energy Policy Act of 1992, and related rules and orders. The ICA requires, among other things, that tariff rates for common carrier crude oil pipelines be “just and reasonable” and not unduly discriminatory and that such rates and terms and conditions of service be filed with the FERC. The ICA permits interested persons to challenge proposed new or changed rates. The FERC is authorized to suspend the effectiveness of such rates for up to seven months. If the FERC finds that the new or changed rate is unlawful, it may require the carrier to pay refunds for the period that the rate was in effect. The FERC also may investigate, upon complaint or on its own motion, rates that are already in effect and may order a carrier to change its rates prospectively. Upon an appropriate showing, a shipper may obtain reparations for damages sustained for a period of up to two years prior to the filing of a complaint. The rates charged for crude oil pipeline services are generally increased annually based on a FERC-approved indexing methodology, which allows a pipeline to charge rates up to a prescribed ceiling that changes annually based on the year-to-year change in the Producer Price Index, or PPI. A rate increase within the indexed rate ceiling is presumed to be just and reasonable unless a protesting party can demonstrate that the rate increase is substantially in excess of the pipeline’s operating costs. During the five-year period commencing July 1, 2011 and ending June 30, 2016, pipelines have been permitted by the FERC to adjust these indexed rate ceilings annually by the PPI plus 2.65%. On December 17, 2015, the FERC issued an order establishing a new index level of PPI plus 1.23% for the five-year period commencing July 1, 2016. As an alternative to this indexing methodology, pipelines may also choose to support changes in their rates based on a cost-of-service methodology, by obtaining advance approval to charge “market-based rates,” or by charging “settlement rates” agreed to by all affected shippers.
Currently, the crude oil gathering system servicing the East Pony IDP transports crude oil in interstate commerce. In addition, the Saddle Butte crude oil gathering system transports crude oil in interstate commerce. We have been granted a temporary waiver of the tariff and reporting requirements for both of these crude oil gathering systems. Therefore, currently the FERC’s regulation of these two crude oil gathering systems is limited to requiring us to maintain our books and records consistent with the FERC’s recordkeeping requirements. The classification and regulation of these crude oil gathering pipelines are subject to change based on changed circumstances on the pipeline or on future determinations by the FERC, federal courts, Congress or by regulatory commissions, courts or legislatures in the states in which our crude oil gathering pipelines are located. If it is determined that some or all of our crude oil gathering pipeline systems are subject to the FERC’s jurisdiction under the ICA, and are not otherwise exempt from any applicable regulatory requirements, such systems could be subject to cost-of-service rates and common carrier requirements that could adversely affect the results of our operations on and revenues associated with those systems.
In addition to the crude oil gathering system servicing the East Pony IDP and the Saddle Butte system, we own interests in other crude oil gathering pipelines that do not provide interstate services and are not subject to regulation by the FERC. However, the distinction between FERC-regulated interstate pipeline transportation, on the one hand, and intrastate pipeline transportation, on the other hand, is a fact-based determination. The classification and regulation of these crude oil gathering pipelines are subject to change based on future determinations by the FERC, federal courts, Congress or by regulatory commissions, courts or legislatures in the states in which the our crude oil gathering pipelines are located. We cannot provide assurance that the FERC will not in the future, either at the request of other entities or on its own initiative, determine that some

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or all of our gathering pipeline systems and the services we provide on those systems are within the FERC’s jurisdiction. If it was determined that some or all of our gathering pipeline systems are subject to the FERC’s jurisdiction under the ICA, and are not otherwise exempt from any applicable regulatory requirements, the imposition of possible cost-of-service rates and common carrier requirements on those systems could adversely affect the results of our operations on and revenue associated with those systems.
Other Crude Oil and Natural Gas Regulation
The State of Colorado is engaged in a number of initiatives that may impact our operations directly or indirectly. To the extent that the State of Colorado adopts new regulations that impact Noble, as our primary current customer, the impact of these regulations on Noble production activity may result in decreased demand from Noble for the services we provide.
In 2014, by executive order, Colorado Governor Hickenlooper created a 21-member Oil and Gas Task Force (the Task Force) made up of representatives of local governments, civic entities, environmental organizations and industry for the purpose of making recommendations regarding oil and gas development in communities. After 18 months the Task Force, which included a representative from Noble, concluded its activities on February 27, 2015. Nine recommendations were sent to the governor, seven of which were unanimously supported by members of the Task Force. All nine recommendations have been adopted by legislation or regulation. The COGCC completed work on new rules which govern the siting of large oil and gas operations in urban areas and require greater coordination of drilling operations with local governments. These new rules took effect in March 2016 and there is strong public support for them to be implemented.
In February 2013, the COGCC approved new setback rules for crude oil and natural gas wells and production facilities located in close proximity to occupied buildings. Previously, the COGCC allowed setback distances of 150 feet in rural areas and 350 feet in high density urban areas. These have been increased to a uniform 500-foot statewide setback from occupied buildings and 1,000 feet from high occupancy building units. The new setback rules also require operators to utilize increased mitigation measures to limit potential drilling impacts to surface owners and the owners of occupied building units. In addition, the new rules require advance notice to surface owners, the owners of occupied buildings and local governments prior to the filing of an application for permit to drill or oil and gas location assessment as well as expanded outreach and communication efforts by an operator.
We continue to monitor proposed and new regulations and legislation in all our operating jurisdictions to assess the potential impact on our company. Concurrently, we are engaged in extensive public education and outreach efforts with the goal of engaging and educating the general public and communities about the economic and environmental benefits of safe and responsible crude oil and natural gas development.
Environmental Matters
General
Our gathering pipelines, crude oil treating facilities and produced water facilities are subject to certain federal, state and local laws and regulations governing the emission or discharge of materials into the environment or otherwise relating to the protection of the environment.
As an owner or operator of these facilities, we comply with these laws and regulations at the federal, state and local levels. These laws and regulations can restrict or impact our business activities in many ways, such as:
requiring the acquisition of permits to conduct regulated activities;
restricting the way we can handle or dispose of our materials or wastes;
limiting or prohibiting construction, expansion, modification and operational activities based on National Ambient Air Quality Standards (NAAQS) and in sensitive areas, such as wetlands, coastal regions or areas inhabited by endangered species;
requiring remedial action to mitigate pollution conditions caused by our operations or attributable to former operations;
enjoining, or compelling changes to, the operations of facilities deemed not to be in compliance with permits issued pursuant to such environmental laws and regulations;
requiring noise, lighting, visual impact, odor or dust mitigation, setbacks, landscaping, fencing and other measures; and
limiting or restricting water use.
Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements and the issuance of orders enjoining current and future operations. Certain environmental statutes impose strict joint and several liability for costs required to clean up and restore sites where hazardous substances have been disposed or otherwise released. Moreover, it is not

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uncommon for neighboring landowners and other third parties to file claims for property damage or possibly personal injury allegedly caused by the release of substances or other waste products into the environment.
The trend in environmental regulation has been to place more restrictions and limitations on activities that may affect the environment. Thus, there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate. When possible, we attempt to anticipate future regulatory requirements that might be imposed and plan accordingly to manage the costs of such compliance.
Our producers are subject to various environmental laws and regulations, including the ones described below, and could similarly face suspension of activities or substantial fines and penalties or other costs resulting from noncompliance with such laws and regulations. Any costs incurred to comply with or fines and penalties imposed related to alleged violations of environmental law that have the potential to impact or curtail production from the producers utilizing our midstream assets could subsequently reduce throughput on our systems and in turn adversely affect our business and results of operations.
Climate Change and Air Quality Standards
Our operations are subject to the CAA and comparable state and local requirements. The CAA contains provisions that may result in the imposition of certain pollution control requirements with respect to air emissions from our operations. We may be required to incur certain capital expenditures for air pollution control equipment in connection with maintaining or obtaining pre-construction and operating permits and approvals addressing other air emission-related issues.
For example, in February 2014, Colorado’s Air Quality Control Commission approved comprehensive changes to Regulation 7 that governs emissions from crude oil and natural gas activities, including the nation’s first-ever regulations designed to detect and reduce methane emissions. The EPA has also acted to add requirements that control methane emissions from crude oil and natural gas activities. In June 2016, the EPA finalized these new regulations by setting methane emission standards for new and modified oil and natural gas production and natural gas processing and transmission facilities. These rules generally include requirements for pneumatic devices and storage tanks to minimize leaks, as well as requirements for a leak detection and repair program. However, in June 2017, the EPA published a proposed rule to stay certain portions of these 2016 standards for two years and reconsider the entirety of the 2016 standards but has not yet published a final rule and, as a result, the 2016 standards are currently in effect but future implementation of the 2016 standards is uncertain at this time. To the extent implemented, these regulations could result in increased costs for our operations and for the operations of Noble. Separately, the EPA finalized rules in June 2016 that resolved how oil and gas production facility emissions must be aggregated under the CAA permitting program. This action clarified certain permitting requirements, yet could still impact permitting and compliance costs.
Moreover, on June 2, 2015, the U.S. District Court of Colorado entered as a final judgment (the “Consent Decree”) between the United States, the State of Colorado and Noble to improve air emission control systems at a number of its condensate storage tanks, and certain of these storage tank systems were transferred to the Partnership after the Consent Decree became effective and remain subject to such Consent Decree. The Consent Decree requires, in accordance with a schedule (i) the performance of injunctive relief that will, among other things, evaluate, monitor, verify, and report on the adequate design, operation, and maintenance of certain aspects of tank systems to handle potential peak instantaneous vapor flow rates and (ii) the completion of certain environmental mitigation actions and supplemental environmental projects that may impact certain tank systems and payment of civil penalties.
Also, in October 2015, the EPA issued final regulations that lower the NAAQS for ozone from 75 parts per billion, or ppb, for both the 8-hour primary and secondary standards, to 70 ppb. The EPA was required to designate attainment and nonattainment areas by October 2017, but missed the deadline. The EPA published a final rule in November 2017 that issued “attainment/unclassifiable” or “unclassifiable” area designations pursuant to the 2015 rule but, to date, no non-attainment area designations have been issued by the agency. States with moderate or higher nonattainment areas must submit a state implementation plan, or “SIP”, by October 2021. While the more stringent ozone NAAQS is not directly applicable to our operations, it may require Colorado to further reconsider its current SIP development and enact additional regulations or require additional permitting requirements. These requirements could go beyond those currently contemplated by the State to further reduce the ozone precursor emissions of volatile organic compounds and nitrogen oxides from certain emissions sources. In turn these potential requirements could apply to our operations and result in increased permitting and compliance costs.
Colorado Air Compliance Order on Consent
In December 2015, Noble received a proposed Compliance Order on Consent, or COC, from the Colorado Department of Public Health and Environment’s Air Pollution Control Division, or APCD, to resolve allegations of noncompliance associated with certain engines subject to various General Permit 02 conditions and/or individual permit conditions as well as certain emission control devices subject to various individual permit conditions that applied to assets currently owned and operated by both Noble and Midstream Services. In May 2016, prior to the IPO of our Common Units, at a time when Noble owned all of

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the interests in us and our subsidiaries, including Operating, Noble reached a final resolution with APCD on behalf of itself and Midstream Services and Colorado River DevCo LP, which requires completion of compliance testing, modification of certain permits, payment of a civil penalty of $44,695, and an expenditure of no less than $178,780 on an approved supplement environmental project. This resolution is not believed to have a material adverse effect on our financial position, results of operations or cash flows, and Noble has agreed to fully indemnify us for all matters relating hereto under our omnibus agreement.
Compliance with these or other new legal requirements could, among other things, require installation of new emission controls on some of our equipment, result in longer permitting timelines, and significantly increase our capital expenditures and operating costs, which could adversely impact our business.
In response to findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment, the EPA has adopted regulations under existing provisions of the CAA, that, among other things, establish Prevention of Significant Deterioration, or PSD, construction and Title V operating permit reviews for certain large stationary sources that emit GHGs. We currently do not operate any Title V sources, but our facilities could become subject to Title V permitting requirements in the future. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards that will be established by the states or, in some cases, by the EPA on a case-by-case basis. These EPA rulemakings could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore crude oil and natural gas production sources in the U.S. on an annual basis.
Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations. Substantial limitations on GHG emissions could also adversely affect demand for the crude oil and natural gas we gather. Recently, activists concerned about the potential effects of climate change have directed their attention at sources of funding for fossil-fuel energy companies, which has resulted in certain financial institutions, funds and other sources of capital restricting or eliminating their investment in oil and natural gas activities. Ultimately, this could make it more difficult to secure funding for energy infrastructure projects, such as pipelines and terminal facilities. Notwithstanding potential risks related to climate change, the International Energy Agency estimates that global energy demand will continue to rise and will not peak until after 2040 and that oil and gas will continue to represent a substantial percentage of global energy use over that time. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events; if any such effects were to occur, they could have a materially adverse effect on our operations or Noble’s exploration and production operations, which in turn could affect demand for our services.
Hazardous Substances and Waste
Our operations are subject to environmental laws and regulations relating to the management and release of hazardous substances or solid wastes, including petroleum hydrocarbons. These laws generally regulate the generation, storage, treatment, transportation and disposal of solid and hazardous waste, and may impose strict, joint and several liability for the investigation and remediation of areas at a facility where hazardous substances may have been released or disposed. For instance, the Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, also known as the Superfund law, and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that contributed to the release of a hazardous substance into the environment. These persons include current and prior owners or operators of the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Under CERCLA, these persons may be subject to joint and several strict liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. Despite the “petroleum exclusion” of CERCLA Section 101(14) that currently encompasses crude oil and natural gas, we may nonetheless handle hazardous substances within the meaning of CERCLA, or similar state statutes, in the course of our ordinary operations and, as a result, may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment.
We also generate solid wastes, including hazardous wastes that are subject to the requirements of the Resource Conservation and Recovery Act, or RCRA, and comparable state statutes. While RCRA regulates both solid and hazardous wastes, it imposes strict requirements on the generation, storage, treatment, transportation and disposal of hazardous wastes. Certain petroleum production wastes are excluded from RCRA’s hazardous waste regulations. However, it is possible that these wastes, which could include wastes currently generated during our operations, will in the future be designated as hazardous wastes and therefore be subject to more rigorous and costly disposal requirements. For example, in December 2016, the EPA and environmental groups entered into a consent decree to address EPA’s alleged failure to timely assess its RCRA Subtitle D

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criteria regulations exempting certain exploration and production related oil and gas wastes from regulation as hazardous wastes. The consent decree requires EPA to propose a rulemaking no later than March 15, 2019 for any revisions relating to oil and gas wastes or to sign a determination that revision of the regulations is not necessary. Any such changes in the laws and regulations could have a material adverse effect on our maintenance capital expenditures and operating expenses.
We currently own or lease properties where petroleum hydrocarbons are being or have been handled for many years. Although we have utilized operating and disposal practices that were standard in the industry at the time, petroleum hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by us or on or under the other locations where these petroleum hydrocarbons and wastes have been taken for treatment or disposal. In addition, certain of these properties have been operated by third parties whose treatment and disposal or release of petroleum hydrocarbons or other wastes was not under our control. These properties and wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater) or to perform remedial operations to prevent future contamination. We are not currently aware of any facts, events or conditions relating to the application of such requirements that could reasonably have a material impact on our operations or financial condition.
Water
The Federal Water Pollution Control Act of 1972, also referred to as the Clean Water Act, or CWA, and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants into navigable waters. Pursuant to the CWA and analogous state laws, permits must be obtained to discharge pollutants into state and federal waters. Provisions of the CWA require authorization from the U.S. Army Corps of Engineers, or the Corps, prior to the placement of dredge or fill material into jurisdictional waters. On June 29, 2015, the EPA and the Corps published the final rule defining the scope of the EPA’s and Corps’ jurisdiction, known as the “Clean Water Rule.” The Clean Water Rule has been challenged in multiple federal courts; however, at this time, we cannot predict the outcome of this litigation. Subsequently, the EPA and the Corps proposed a rulemaking in June 2017 to repeal the June 2015 rule, and also announced their intent to issue a new rule defining the Clean Water Act’s jurisdiction. Both agencies also published a proposed rule in November 2017 delaying implementation of the Clean Water Rule for two years. As a result, future implementation of the June 2015 rule is uncertain at this time. To the extent the rule expands the scope of the CWA’s jurisdiction, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas.
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. In 2015, Colorado adopted new rules for crude oil and natural gas developments within floodplains and sampling of groundwater for hydrocarbons and other indicators before and after drilling crude oil and natural gas wells. We believe that compliance with existing permits and compliance with foreseeable new permit requirements will not have a material adverse effect on our financial condition or results of operations.
The Oil Pollution Act of 1990, or OPA, addresses prevention, containment and cleanup, and liability associated with crude oil pollution. OPA applies to vessels, offshore platforms, and onshore facilities, including terminals, pipelines, and transfer facilities. OPA subjects owners of such facilities to strict liability for containment and removal costs, natural resource damages, and certain other consequences of crude oil spills into jurisdictional waters. Any unpermitted release of petroleum or other pollutants from our operations could result in government penalties and civil liability under OPA.
Colorado Water Quality Control Act
In January 2017, we received a Notice of Violation/Cease and Desist Order, or NOV/CDO, advising us of alleged violations of the Colorado Water Quality Control Act, or CWQCA, and its implementing regulations as it relates to construction activities associated with oil and gas exploration and/or production within our Wells Ranch IDP located in Weld County, Colorado, or Permit.  The NOV/CDO further orders us to cease and desist from all violations of the CWQCA, the regulations and the Permit and to undertake certain corrective actions. Given the uncertainty associated with administrative actions of this nature, we are unable to predict the ultimate outcome of this action at this time but believe that the resolution of this action will not have a material adverse effect on our financial position, results of operations or cash flows.

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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. Recently, however, several federal agencies have asserted jurisdiction over the process. For example, the EPA, has moved forward with various regulatory actions, including the issuance of new regulations requiring green completions for hydraulically fractured wells, and emission requirements for certain midstream equipment. Also, in June 2016, the EPA finalized rules which prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants. Certain environmental groups have also suggested that additional laws may be needed to more closely and uniformly regulate the hydraulic fracturing process. We cannot predict whether any such legislation will be enacted and if so, what its provisions would be. Additional levels of regulation and permits required through the adoption of new laws and regulations at the federal, state or local level could lead to delays, increased operating costs and process prohibitions that could reduce the volumes of crude oil and natural gas that move through our gathering systems and decrease demand for our water services, which in turn could materially adversely impact our revenues.
Endangered Species
The Endangered Species Act, or ESA, and analogous state laws restrict activities that may affect listed endangered or threatened species or their habitats. If endangered species are located in areas where we operate, our operations or any work performed related to them could be prohibited or delayed or expensive mitigation may be required. While some of our operations may be located in areas that are designated as habitats for endangered or threatened species, we believe that we are in compliance with the ESA. In addition, as a result of a settlement approved by the U.S. District Court for the District of Columbia on September 9, 2011, the U.S. Fish and Wildlife Service was required to review and consider the listing of numerous species as endangered under the ESA by no later than the completion of the agency’s 2017 fiscal year. The agency missed the deadline; however, additional listings under the ESA and similar state laws could result in the imposition of restrictions on our operations and consequently have a material adverse effect on our business.
National Environmental Policy Act
Our operations on federal lands are subject to the National Environmental Policy Act, or NEPA. Under NEPA, federal agencies, including the Department of Interior must evaluate major agency actions having the potential to significantly impact the environment. This review can entail a detailed evaluation including an Environmental Impact Statement. This process can result in significant delays and may result in additional limitations and costs associated with projects on federal lands.

Title to Our Properties
Many of our real estate interests in land were acquired pursuant to easements, rights-of-way, permits, surface use agreements, joint use agreements, licenses and other grants or agreements from landowners, lessors, easement holders, governmental authorities, or other parties controlling the surface or subsurface estates of such land, or, collectively, Real Estate Agreements, that were issued to or entered into by Noble, one of its affiliates or one of their predecessors-in-interest and transferred to us in December of 2015. Since that time, we have been acquiring additional Real Estate Agreements in our own name or by transfer from Noble. The Real Estate Agreements and related interests that we have taken by assignment were acquired without any material challenge known to us relating to the title to the land upon which the assets are located, and we believe that we have satisfactory rights and interests to conduct our operations on such lands. We have no knowledge of any challenge to the underlying title of any material real estate interests held by us or to our title to any material real property agreements, and we believe that we have satisfactory title to all of our material real estate interests.
We hold various rights and interests to receive, deliver and handle water in connection with Noble’s production operations, or, collectively, Water Interests, that also were obtained by Noble or its predecessor in interest and transferred to us. Pursuant to these Water Interests, Noble retains title to the water. In the future, we will also acquire additional Water Interests in our own name or by transfer from Noble as necessary to conduct such operations. We are not aware of any challenges to any Water Interests or to the use of any water or water rights related to Water Interests. With respect to our third party customer, we will not take title to the water that we handle and will only have the right to receive, deliver and handle such water.

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Under our omnibus agreement, Noble will indemnify us for any failure to have certain real estate interests, Real Estate Agreements or Water Interests necessary to own and operate our assets in substantially the same manner that they were owned and operated prior to the closing of the IPO. Noble’s indemnification obligation will be limited to losses for which we notify Noble prior to the third anniversary of the closing of the IPO and will be subject to a $500,000 aggregate deductible before we are entitled to indemnification.
Seasonality
Demand for crude oil and natural gas generally decreases during the spring and fall months and increases during the summer and winter months. However, seasonal anomalies such as mild winters or mild summers sometimes lessen this fluctuation. In addition, certain crude oil and natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer. This can also lessen seasonal demand fluctuations. These seasonal anomalies can increase demand for crude oil and natural gas during the summer and winter months and decrease demand for crude oil and natural gas during the spring and fall months. In respect of our completed midstream systems, we do not expect seasonal conditions to have a material impact on our throughput volumes. Severe or prolonged winters may, however, impact our ability to complete additional well connections or construction projects, which may impact the rate of our growth. In addition, severe weather may also impact or slow the ability of Noble to execute its drilling and development plan and increase operating expenses associated with repairs or anti-freezing operations.
Customers
For the year ended December 31, 2017, 94% of our revenues are from Noble and its affiliates. For the years ended December 31, 2016 and 2015, 100% of our revenues are from Noble and its affiliates.
Competition
As a result of our relationship with Noble and the long-term dedications to our midstream assets, we do not compete with other midstream companies to provide Noble with midstream services to its existing upstream assets in Weld County, Colorado, and we will not compete for Noble’s business as it continues to develop upstream production in Weld County, Colorado. Although Noble will continue to use third party service providers for certain midstream services in the Delaware Basin until the expiration or termination of certain pre-existing dedications, we will not compete for Noble’s business in the Delaware Basin after the expiration of such dedications. However, we will face competition in providing services on the acreage that is subject to our ROFR rights because Noble is only required to dedicate such acreage to us if we are able to offer services to Noble on the same or better terms as the applicable third party service provider.
As we seek 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 expand to provide midstream services to third party producers, we will also face a high level of competition. Competition is often the greatest in geographic areas experiencing robust drilling by producers and during periods of high commodity prices for crude oil, natural gas or NGLs.
Employees
The officers of our General Partner manage our operations and activities. All of the employees required to conduct and support our operations are employed by Noble and are subject to the operational services and secondment agreement that we entered into with Noble in connection with our IPO. As of December 31, 2017, Noble employed approximately 143 people who provide direct support to our operations pursuant to the operational services and secondment agreement.
Office
The principal office of our Partnership is located at 1001 Noble Energy Way, Houston, Texas 77070.
Insurance
Our business is subject to all of the inherent and unplanned operating risks normally associated with the gathering and treating of water, crude oil and natural gas and the distribution and storage of water. Such risks include weather, fire, explosion, pipeline disruptions and mishandling of fluids, any of which could result in damage to, or destruction of, gathering and storage facilities and other property, environmental pollution, injury to persons or loss of life. As protection against financial loss resulting from many, but not all of these operating hazards, pursuant to the terms of the omnibus agreement, we have insurance coverage, including certain physical damage, business interruption, employer’s liability, third party liability and worker’s compensation insurance. Our General Partner believes this insurance is appropriate and consistent with industry practice. We cannot, however, assure you that this insurance will be adequate to protect us from all material expenses related to potential future claims for personal and property damage or that these levels of insurance will be available in the future at economical prices. Our insurance coverage is purchased through a captive insurance company that is an affiliate of Noble. Most of this captive

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insurance is reinsured into the commercial market. To the extent Noble experiences covered losses under the excess liability insurance policies, the limit of our coverage for potential losses may be decreased.
Available Information
Our Common Units are listed and traded on the NYSE under the symbol “NBLX.” Our website is www.nblmidstream.com. We make our periodic reports and other information filed with or furnished to the U.S. Securities and Exchange Commission, or SEC, available, free of charge, through our website, as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Alternatively, you may access these reports at the SEC’s website at www.sec.gov. Information on our website or any other website is not incorporated by reference into this Annual Report and does not constitute a part of this Annual Report.
Our Audit Committee charter is also posted on our website under “About Us – Corporate Governance” and is available in print upon request made by any unitholder to the Investor Relations Department. Copies of our Code of Conduct and Code of Ethics for Financial Officers, or the Codes, are also posted on our website under the “Corporate Governance” section. Within the time period required by the SEC and the NYSE, as applicable, we will post on our website (www.nblmidstream.com/about-us/corporate-governance/) any modifications to the Codes and any waivers applicable to senior officers as defined in the applicable Code, as required by the Sarbanes-Oxley Act of 2002.

Item 1A.    Risk Factors
Limited partner interests are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. You should carefully consider the following risk factors and all other information set forth in this Annual Report on Form 10-K.
If any of the following risks were to occur, our business, financial condition, results of operations, cash flows and ability to make cash distributions could be materially adversely affected. In that case, we may not be able to pay the minimum quarterly distribution on our common units, the trading price of our common units could decline and you could lose all or part of your investment.
Risks Related to Our Business
We derive a substantial portion of our revenue from Noble. If Noble changes its business strategy, alters its current drilling and development plan on our dedicated acreage, or otherwise significantly reduces the volumes of crude oil, natural gas, produced water or fresh water with respect to which we perform midstream services, our revenue would decline and our business, financial condition, results of operations, cash flows and ability to make distributions to our unitholders would be materially and adversely affected.
A substantial portion of our commercial agreements are with Noble or its affiliates. Accordingly, because we expect to initially 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

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commitments with respect to future dedications; and other non-payment or non-performance by Noble, including with respect to our commercial agreements, which do not contain minimum volume commitments. Noble is currently operating one drilling rig in the DJ Basin and six drilling rigs in the Delaware Basin. A decrease in the number of drilling rigs that Noble operates on our dedicated acreage could result in lower throughput on our midstream infrastructure. Furthermore, we cannot predict the extent to which Noble’s businesses would be impacted if conditions in the energy industry were to deteriorate nor can we estimate the impact such conditions would have on Noble’s ability to execute its drilling and development plan on our dedicated acreage or to perform under our commercial agreements. Any material non-payment or non-performance by Noble under our commercial agreements would have a significant adverse impact on our business, financial condition, results of operations and cash flows and could therefore materially adversely affect our ability to make cash distributions to our unitholders at the minimum quarterly distribution rate or at all. Our long-term commercial agreements with Noble carry initial terms for 15 years, and there is no guarantee that we will be able to renew or replace these agreements on equal or better terms, or at all, upon their expiration. Our ability to renew or replace our commercial agreements following their expiration at rates sufficient to maintain our current revenues and cash flows could be adversely affected by activities beyond our control, including the activities of our competitors and Noble.
In addition to our commercial agreements with Noble, we provide crude oil and water related services for an unaffiliated, non-investment grade third party customer. 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. To the extent we derive substantial income from or commit to capital projects to service new or existing customers, each of the risks indicated above would apply to such arrangements and customers.
In the event any customer, including Noble, elects to sell acreage that is dedicated to us to a third party, the third party’s financial condition could be materially worse than the customer with whom we have contracted, and thus we could be subject to the nonpayment or nonperformance by the third party.
In the event a customer, including Noble, elects to sell acreage that is dedicated to us to a third party, the third party’s financial condition could be materially worse than the original contracting customer. In such a case, we may be subject to risks of loss resulting from nonpayment or nonperformance by the third party, which risks may increase during periods of economic uncertainty. Furthermore, the third party may be subject to their own operating and regulatory risks, which increases the risk that they may default on their obligations to us. Any material nonpayment or nonperformance by the third party could reduce our ability to make distributions to our unitholders.
We may not generate sufficient distributable cash flow to enable us to make quarterly distributions to our unitholders at our current distribution rate.
We may not generate sufficient distributable cash flow to enable us to make quarterly distributions at our current distribution rate.
The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:
the volumes of natural gas we gather, the volumes of crude oil we gather, the volumes of produced water we collect, clean or dispose of and the volumes of fresh water we distribute and store and the number of wells that have access to our crude oil treating facilities;
market prices of crude oil, natural gas and NGLs and their effect on our customers’ drilling and development plan on our dedicated acreage and the volumes of hydrocarbons that are produced on our dedicated acreage and for which we provide midstream services;
our customers’ ability to fund their drilling and development plans on our dedicated acreage;
downstream processing and transportation capacity constraints and interruptions, including the failure of our customers to have sufficient contracted processing or transportation capacity;
the levels of our operating expenses, maintenance expenses and general and administrative expenses;
regulatory action affecting: (i) the supply of, or demand for, crude oil, natural gas, NGLs and water, (ii) the rates we can charge for our midstream services, (iii) the terms upon which we are able to contract to provide our midstream services, (iv) our existing gathering and other commercial agreements or (v) our operating costs or our operating flexibility;
the rates we charge third parties for our midstream services;
prevailing economic conditions; and
adverse weather conditions.


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In addition, the actual amount of distributable cash flow that we generate will also depend on other factors, some of which are beyond our control, including:
the level and timing of our capital expenditures;
our debt service requirements and other liabilities;
our ability to borrow under our debt agreements to fund our capital expenditures and operating expenditures and to pay distributions;
fluctuations in our working capital needs;
restrictions on distributions contained in any of our debt agreements;
the cost of acquisitions, if any;
the fees and expenses of our General Partner and its affiliates (including Noble) that we are required to reimburse;
the amount of cash reserves established by our General Partner; and
other business risks affecting our cash levels.
Because of the natural decline in production from existing wells, our success, in part, depends on our ability to maintain or increase hydrocarbon throughput volumes on our midstream systems, which depends on our customers’ levels of development and completion activity on our dedicated acreage.
The level of crude oil and natural gas volumes handled by our midstream systems depends on the level of production from crude oil and natural gas wells dedicated to our midstream systems, which may be less than expected and which will naturally decline over time. In order to maintain or increase throughput levels on our midstream systems, we must obtain production from wells completed by Noble and any third party customers on acreage dedicated to our midstream systems or execute agreements with other third parties in our areas of operation.
We have no control over Noble’s or other producers’ levels of development and completion activity in our areas of operation, the amount of reserves associated with wells connected to our systems or the rate at which production from a well declines. In addition, we have no control over Noble or other producers or their exploration and development decisions, which may be affected by, among other things:
the availability and cost of capital;
prevailing and projected crude oil, natural gas and NGL prices;
demand for crude oil, natural gas and NGLs;
levels of reserves;
geologic considerations;
changes in the strategic importance our customers assign to development in the DJ Basin or the Delaware Basin as opposed to their other operations, which could adversely affect the financial and operational resources our customers are willing to devote to development of our dedicated acreage;
increased levels of taxation related to the exploration and production of crude oil, natural gas and NGLs in our areas of operation;
environmental or other governmental regulations, including the availability of permits, the regulation of hydraulic fracturing and a governmental determination that multiple facilities are to be treated as a single source for air permitting purposes; and
the costs of producing crude oil, natural gas and NGLs and the availability and costs of drilling rigs and other equipment.
Due to these and other factors, even if reserves are known to exist in areas served by our midstream assets, producers, including Noble, may choose not to develop those reserves. If producers choose not to develop their reserves, or they choose to slow their development rate, in our areas of operation, utilization of our midstream systems will be below anticipated levels. Our inability to provide increased services resulting from reductions in development activity, coupled with the natural decline in production from our current dedicated acreage, would result in our inability to maintain the then-current levels of utilization of our midstream assets, which could materially adversely affect our business, financial condition, results of operations, cash flows and ability to make cash distributions.
If our customers do not maintain their drilling activities on our dedicated acreage, the demand for our fresh water services could be reduced, which could have a material adverse effect on our results of operations, cash flows and ability to make distributions to our unitholders.
The fresh water services we provide to our customers assist in their drilling activities. If our customers do not maintain their drilling activities on our dedicated acreage, their demand for our fresh water services will be reduced regardless of whether we continue to provide our other midstream services on their production. If the demand for our fresh water services declines for this or any other reason, our results of operations, cash flows and ability to make distributions to our unitholders could be materially adversely affected.

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A substantial portion of our assets are controlling ownership interests in our development companies. Because our interests in our development companies represent almost all of our cash-generating assets, our cash flow will depend entirely on the performance of our development companies and their ability to distribute cash to us.
We have a holding company structure, and the primary source of our earnings and cash flow consists exclusively of the earnings of and cash distributions from our DevCos. Therefore, our ability to make quarterly distributions to our unitholders will be almost entirely dependent upon the performance of our DevCos and their ability to distribute funds to us. We are the sole member of the General Partner of each of our DevCos, and we control and manage our DevCos through our ownership of our DevCos’ respective General Partners.
The limited partnership agreement governing each DevCo requires that the General Partner of such DevCo cause such DevCo to distribute all of its available cash each quarter, less the amounts of cash reserves that such General Partner determines are necessary or appropriate in its reasonable discretion to provide for the proper conduct of such DevCo’s business.
The amount of cash each DevCo generates from its operations will fluctuate from quarter to quarter based on events and circumstances and the actual amount of cash each DevCos will have available for distribution to its partners, including us, also will depend on certain factors.
Our midstream assets are currently primarily located in the DJ Basin in Colorado and the Delaware Basin in Texas, making us vulnerable to risks associated with operating in a limited geographic area.
Our midstream assets are currently located primarily in the DJ Basin in Colorado and the Delaware Basin in Texas. As a result of this concentration, we will be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in these areas caused by governmental regulation, market limitations, water shortages, drought related conditions or other weather-related conditions or interruption of the processing or transportation of crude oil and natural gas. If any of these factors were to impact the DJ Basin or Delaware Basin more than other producing regions, our business, financial condition, results of operations and ability to make cash distributions could be adversely affected relative to other midstream companies that have a more geographically diversified asset portfolio.
We cannot predict the rate at which our customers will develop acreage that is dedicated to us or the areas they will decide to develop.
Our acreage dedication and commitments from our customers cover midstream services in a number of areas that are at the early stages of development, in areas that our customers are still determining whether to develop and in areas where we may have to acquire operating assets from third parties. In addition, our customers own acreage in areas that are not dedicated to us. We cannot predict which of these areas our customers will determine to develop and at what time. Our customers may decide to explore and develop areas in which we have a smaller operating interest in the midstream assets that service that area, or where the acreage is not dedicated to us, rather than areas in which we have a larger operating interest in the midstream assets that service that area. Our customer’s decisions to develop acreage that is not dedicated to us or that we have a smaller operating interest in may adversely affect our business, financial condition, results of operations, cash flows and ability to make cash distributions.
While we have been granted a right of first refusal to provide midstream services on certain acreage that Noble currently owns and on all acreage that Noble acquires onshore in the U.S., portions of this acreage may be subject to preexisting dedications that may require Noble to use third parties for midstream services.
Although Noble has granted us a ROFR to provide the midstream services covered by our commercial agreements as well as natural gas processing on all of the dedicated acreage where not all of such services are currently provided, on all of its currently owned acreage in the DJ Basin that has not yet been dedicated, on certain of its currently owned acreage in the Eagle Ford Shale and on all of its future acquired acreage onshore in the United States (other than in the Marcellus Shale), portions of this acreage may be subject to preexisting dedications, rights of first refusal, rights of first offer and other preexisting encumbrances that require Noble to use third parties for midstream services, and, as a result, Noble may be precluded from offering us the opportunity to provide these midstream services on this acreage. Because we do not have visibility as to which acreage Noble may acquire or divest, and what existing dedications, rights of first refusal, rights of first offer or other overriding rights may exist on such acreage, we are unable to predict the value, if any, of our ROFR to provide midstream services on Noble’s acreage onshore in the United States.
We may not be able to economically accept an offer from Noble for us to provide services or purchase assets with respect to which we have a right of first refusal.
Noble is required to offer us, prior to contracting for such opportunity with a third party, the opportunity to provide the midstream services covered by our commercial agreements, which include crude oil gathering, natural gas gathering, produced water gathering, fresh water services and crude oil treating, as well as services of a type provided at natural gas processing plants on certain acreage located in the United States that Noble currently owns or in the future acquires or develops. In

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addition, Noble is required to offer us, prior to contracting for such opportunity with a third party, the ownership interest in any midstream assets that are located on the acreage for which Noble has granted us a ROFR to provide services. The acreage and assets subject to this ROFR may be located in areas far from our existing infrastructure or may otherwise be undesirable in the context of our business. In addition, we can make no assurances that the terms at which Noble offers us the opportunity to provide these services or purchase these assets will be acceptable to us. Furthermore, another midstream service provider or third party may be willing to accept an offer from Noble that we are unwilling to accept. Our inability to take advantage of the opportunities with respect to such acreage or assets could adversely affect our growth strategy or our ability to maintain or increase our cash distribution level.
We may be unable to grow by acquiring the non-controlling interests in our DevCos owned by Noble or midstream assets retained, acquired or developed by Noble, which could limit our ability to increase our distributable cash flow.
Part of our strategy for growing our business and increasing distributions to our unitholders is dependent upon our ability to make acquisitions that increase our distributable cash flow. Part of the acquisition component of our growth strategy is based upon our expectation of future divestitures by Noble to us of retained, acquired or developed midstream assets and portions of its retained, non-controlling interests in our DevCos. We have only a ROFO, pursuant to our omnibus agreement that requires Noble to allow us to make an offer with respect to Noble’s retained non-controlling interests in our DevCos to the extent Noble elects to sell these interests. In addition, Noble has granted us a ROFR with respect to opportunities to (1) provide services covered by our commercial agreements as well as services of a type provided at natural gas processing plants on certain acreage located in the United States that Noble currently owns or in the future acquires or develops and (2) purchase ownership interests in any assets currently owned by Noble, or in the future developed or acquired by Noble, for the purpose of providing the services described in clause (1) above, provided, that, such assets are located onshore in the United States and are not used to provide services with respect to production from the Marcellus Shale. Noble is under no obligation to sell its retained interests in our DevCos or offer to sell us additional assets, we are under no obligation to buy any additional interests or assets from Noble and we do not know when or if Noble will decide to sell its retained interests in our DevCos or make any offers to sell assets to us. We may never purchase all or any portion of the non-controlling interests in our DevCos or any of Noble’s retained, acquired or developed midstream assets onshore in the United States (other than in the Marcellus Shale) for several reasons, including the following:
Noble may choose not to sell these non-controlling interests or assets;
we may not accept offers for these assets or make acceptable offers for these equity interests;
we and Noble may be unable to agree to terms acceptable to both parties;
we may be unable to obtain financing to purchase these non-controlling interests or assets on acceptable terms or at all; or
we may be prohibited by the terms of our debt agreements (including our credit facility) or other contracts from purchasing some or all of these non-controlling interests or assets, and Noble may be prohibited by the terms of its debt agreements or other contracts from selling some or all of these non-controlling interests or assets. If we or Noble must seek waivers of such provisions or refinance debt governed by such provisions in order to consummate a sale of these non-controlling interests or assets, we or Noble may be unable to do so in a timely manner or at all.
We do not know when or if Noble will decide to sell all or any portion of its non-controlling interests or will offer us any portion of its assets, and we can provide no assurance that we will be able to successfully consummate any future acquisition of all or any portion of such non-controlling interests in our DevCos or assets. Furthermore, if Noble reduces its ownership interest in us, it may be less willing to sell to us its retained non-controlling interests in our DevCos or its retained assets. In addition, except for our ROFO and ROFR, there are no restrictions on Noble’s ability to transfer its non-controlling interests in our DevCos or its retained assets to a third party or non-controlled affiliate. If we do not acquire all or a significant portion of the non-controlling interests in our DevCos held by Noble or midstream assets from Noble, our ability to grow our business and increase our cash distributions to our unitholders may be significantly limited.
An acquisition from Noble or a third party may reduce, rather than increase, our distributable cash flow or may disrupt our business.
Even if we make acquisitions that we believe will be accretive, these acquisitions may nevertheless result in a decrease in our distributable cash flow.  Any acquisition involves potential risks that may disrupt our business, including the following, among other things:
mistaken assumptions about volumes or the timing of those volumes, revenues or costs, including synergies;
an inability to successfully integrate the acquired assets or businesses;
the assumption of unknown liabilities;
exposure to potential lawsuits;
limitations on rights to indemnity from the seller;
the diversion of management’s and employees’ attention from other business concerns;

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unforeseen difficulties operating in new geographic areas; and
customer or key employee losses at the acquired businesses.
We may not be able to attract dedications of additional third party volumes, in part because our industry is highly competitive, which could limit our ability to grow and increase our dependence on Noble.
Part of our long-term growth strategy includes diversifying our customer base by identifying additional opportunities to offer services to third parties in our areas of operation. To date and over the near term, a substantial portion of our revenues have been and will be earned from Noble relating to its operated wells on our dedicated acreage. Our ability to increase throughput on our midstream systems and any related revenue from third parties is subject to numerous factors beyond our control, including competition from third parties and the extent to which we have available capacity when requested by third parties. Any lack of available capacity on our systems for third party volumes will detrimentally affect our ability to compete effectively with third party systems for crude oil and natural gas from reserves associated with acreage other than our then-current dedicated acreage. In addition, some of our competitors for third party volumes have greater financial resources and access to larger supplies of crude oil and natural gas than those available to us, which could allow those competitors to price their services more aggressively than we do.
Our efforts to attract additional third parties as customers may be adversely affected by our relationship with Noble and the fact that a substantial majority of the capacity of our midstream systems will be necessary to service its production on our dedicated acreage and our desire to provide services pursuant to fee-based agreements. As a result, we may not have the capacity to provide services to additional third parties and/or potential third party customers may prefer to obtain services pursuant to other forms of contractual arrangements under which we would be required to assume direct commodity exposure. In addition, potential third party customers who are significant producers of crude oil and natural gas may develop their own midstream systems in lieu of using our systems. All of these competitive pressures could have a material adverse effect on our business, results of operations, financial condition, cash flows and ability to make cash distributions to our unitholders.
To maintain and grow our business, we will be required to make substantial capital expenditures. If we are unable to obtain needed capital or financing on satisfactory terms, our ability to make cash distributions may be diminished or our financial leverage could increase.
In order to maintain and grow our business, we will need to make substantial capital expenditures to fund our share of growth capital expenditures associated with our operating interests in our DevCos, to purchase or construct new midstream systems, or to fulfill our commitments to service acreage committed to us by our customers. If we do not make sufficient or effective capital expenditures, we will be unable to maintain and grow our business and, as a result, we may be unable to maintain or raise the level of our future cash distributions over the long term. To fund our capital expenditures, we will be required to use cash from our operations, incur debt or sell additional common units or other equity securities. Using cash from our operations will reduce cash available for distribution to our unitholders. Our ability to obtain bank financing or our ability to access the capital markets for future equity or debt offerings may be limited by our financial condition at the time of any such financing or offering and the covenants in our existing debt agreements, as well as by general economic conditions, contingencies and uncertainties that are beyond our control. Also, due to our relationship with Noble, our ability to access the capital markets, or the pricing or other terms of any capital markets transactions, may be adversely affected by any impairment to the financial condition of Noble or adverse changes in Noble’s credit ratings. Any material limitation on our ability to access capital as a result of such adverse changes to Noble could limit our ability to obtain future financing under favorable terms, or at all, or could result in increased financing costs in the future. Similarly, material adverse changes affecting Noble could negatively impact our unit price, limiting our ability to raise capital through equity issuances or debt financing, or could negatively affect our ability to engage in, expand or pursue our business activities, or could also prevent us from engaging in certain transactions that might otherwise be considered beneficial to us. We will also rely on Noble to make its portion of capital expenditures on our assets, and to the extent that Noble is unable or unwilling to make these capital expenditures, we may not be able to grow at our expected rate or at all.
Even if we are successful in obtaining the necessary funds to support our growth plan, the terms of such financings could limit our ability to pay distributions to our unitholders. In addition, incurring additional debt may significantly increase our interest expense and financial leverage, and issuing additional limited partner interests may result in significant unitholder dilution and would increase the aggregate amount of cash required to maintain the then current distribution rate, which could materially decrease our ability to pay distributions at the then prevailing distribution rate. While we have historically received funding from Noble, none of Noble, our General Partner or any of their respective affiliates is committed to providing any direct or indirect financial support to fund our growth.
The amount of cash we have available for distribution to our unitholders depends primarily on our cash flow and not solely on our profitability, which may prevent us from making distributions, even during periods in which we record net income.
The amount of cash we have available for distribution depends primarily upon our cash flow and not solely on our profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we

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record a net loss for financial accounting purposes, and conversely, we might fail to make cash distributions during periods when we record net income for financial accounting purposes.
Increased competition from other companies that provide midstream services, or from alternative fuel sources, could have a negative impact on the demand for our services, which could adversely affect our financial results.
Our ability to renew or replace existing contracts at rates sufficient to maintain current revenues and cash flows could be adversely affected by the activities of our competitors. Our systems compete for third party customers primarily with other crude oil and natural gas gathering systems and fresh and saltwater service providers. Some of our competitors have greater financial resources and may now, or in the future, have access to greater supplies of crude oil and natural gas than we do. Some of these competitors may expand or construct gathering systems that would create additional competition for the services we would provide to third party customers. In addition, potential third party customers may develop their own gathering systems instead of using ours. Moreover, Noble and its affiliates are not limited in their ability to compete with us outside of our dedicated area.
Further, hydrocarbon fuels compete with other forms of energy available to end-users, including electricity and coal. Increased demand for such other forms of energy at the expense of hydrocarbons could lead to a reduction in demand for our services.
All of these competitive pressures could make it more difficult for us to retain our existing customers or attract new customers as we seek to expand our business, which could have a material adverse effect on our business, financial condition, results of operations and ability to make quarterly cash distributions to our unitholders. In addition, competition could intensify the negative impact of factors that decrease demand for natural gas in the markets served by our systems, such as adverse economic conditions, weather, higher fuel costs and taxes or other governmental or regulatory actions that directly or indirectly increase the cost or limit the use of natural gas.
Our construction of new midstream assets may not result in revenue increases and may be subject to regulatory, environmental, political, contractual, legal and economic risks, which could adversely affect our cash flows, results of operations and financial condition and, as a result, our ability to distribute cash to unitholders.
The construction of additions or modifications to our existing systems and the expansion into new production areas to service Noble or our third party customer involve numerous regulatory, environmental, political and legal uncertainties beyond our control, may require the expenditure of significant amounts of capital, and we may not be able to construct in certain locations due to setback requirements or expand certain facilities that are deemed to be part of a single source. Regulations clarifying how oil and gas production facility emissions must be aggregated under the CAA permitting program were finalized in June 2016. This action clarified certain permitting requirements, yet could still impact permitting and compliance costs. Financing may not be available on economically acceptable terms or at all. As we build infrastructure to meet our customers’ needs, we may not be able to complete such projects on schedule, at the budgeted cost or at all.
Our revenues may not increase immediately (or at all) upon the expenditure of funds on a particular project. We may construct facilities to capture anticipated future production growth from Noble or another customer in an area where such growth does not materialize. As a result, new midstream assets may not be able to attract enough throughput to achieve our expected investment return, which could adversely affect our business, financial condition, results of operations, cash flows and ability to make cash distributions.
The construction of additions to our existing assets may require us to obtain new permits or approvals, rights-of-way, surface use agreements or other real estate agreements prior to constructing new pipelines or facilities. We may be unable to timely obtain such rights-of-way to connect new crude oil, natural gas and water sources to our existing infrastructure or capitalize on other attractive expansion opportunities. Additionally, it may become more expensive for us to obtain new rights-of-way or to expand or renew existing rights-of-way, leases or other agreements, and our fees may only be increased above the annual year-over-year increase by mutual agreement between us and our customer. If the cost of renewing or obtaining new agreements increases, our cash flows could be adversely affected.
We are subject to regulation by multiple governmental agencies, which could adversely impact our business, results of operations and financial condition.
We are subject to regulation by multiple federal, state and local governmental agencies. Proposals and proceedings that affect the midstream industry are regularly considered by Congress, as well as by state legislatures and federal and state regulatory commissions, agencies and courts. We cannot predict when or whether any such proposals or proceedings may become effective or the magnitude of the impact changes in laws and regulations may have on our business. However, additions to the regulatory burden on our industry can increase our cost of doing business and affect our profitability.



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The rates of our regulated assets are subject to review and reporting by federal regulators, which could adversely affect our revenues.
Our crude oil gathering system servicing the East Pony IDP transports crude oil in interstate commerce. In addition, the Saddle Butte crude oil gathering system transports 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 both of these crude oil gathering systems. These temporary waivers are subject to revocation in certain circumstances. We are required to inform the FERC of any change in circumstances upon which the waivers were granted. Should the circumstances change, the FERC could find that transportation on the East Pony IDP or Saddle Butte system no longer qualifies for a waiver. In the event that the FERC were to determine that these crude oil gathering systems no longer qualified for the waiver, we would likely be required to comply with the tariff and reporting requirements, including filing a tariff with the FERC and providing a cost justification for the applicable transportation rates, and providing service to all potential shippers, without undue discrimination. A revocation of the temporary waivers for these pipelines could adversely affect the results of our revenues.
We may be required to respond to requests for information from government agencies, including compliance audits conducted by the FERC.
The FERC’s ratemaking policies are subject to change and may impact the rates charged and revenues received on White Cliffs Pipeline and our East Pony IDP and Saddle Butte gathering systems in the event the temporary waivers do not remain in effect, and any other natural gas or liquids pipeline that is determined to be under the jurisdiction of the FERC. On December 15, 2016, FERC issued a Notice of Inquiry requesting energy industry input on how FERC should address income tax allowances in cost-based rates proposed by pipeline companies organized as part of a master limited partnership. FERC’s current policy permits pipelines and storage companies to include a tax allowance in the cost-of-service used as the basis for calculating their regulated rates. For pipelines and storage companies owned by partnerships or limited liability company interests, the current tax allowance policy reflects the actual or potential income tax liability on the FERC jurisdictional income attributable to all partnership or limited liability company interests if the ultimate owner of the interest has an actual or potential income tax liability on such income. FERC issued the Notice of Inquiry in response to a remand from the U.S. Court of Appeals for the D.C. Circuit in United Airlines v. FERC, in which the court determined that FERC had not justified its conclusion that an oil pipeline organized as a partnership would not “double recover” its taxes under the current policy by both including a tax allowance in its cost-based rates and earning a return on equity calculated on a pre-tax basis. We cannot predict whether FERC will successfully justify its conclusion that there is no double recovery of taxes under these circumstances or whether FERC will modify its current policy on either income tax allowances or return on equity calculations for pipeline companies organized as part of a master limited partnership. However, any modification that reduces or eliminates an income tax allowance for pipeline companies organized as a part of a master limited partnership or decreases the return on equity for such pipelines could result in an adverse impact on our revenues associated with the transportation and storage services we provide pursuant to cost-based rates.
Federal and state legislative and regulatory initiatives relating to pipeline safety that require the use of new or more stringent safety controls or result in more stringent enforcement of applicable legal requirements could subject us to increased capital costs, operational delays and costs of operation.
The Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, also known as 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. The Pipeline Safety and Job Creation Act also increases the maximum penalty for violation of pipeline safety regulations from $100,000 to $200,000 per violation per day of violation and from $1.0 million to $2.0 million for a related series of violations. Effective April 27, 2017, to account for inflation, those maximum civil penalties were increased to $209,002 per violation per day, with a maximum of $2,090,022 for a series of violations.
In addition, in May 2016, PHMSA proposed rules that would, if adopted, impose more stringent requirements for certain natural gas lines. Among other things, the proposed rulemaking would extend certain of PHMSA’s current regulatory safety programs for gas pipelines beyond ‘‘high consequence areas’’ to cover gas pipelines found in newly defined ‘‘moderate consequence areas’’ that contain as few as five dwellings within the potential impact area and would also require gas pipelines installed before 1970 that are currently exempted from certain pressure testing obligations to be tested to determine their MAOP. Other new requirements proposed by PHMSA under rulemaking would require pipeline operators to: report to PHMSA in the event of certain MAOP exceedances; strengthen PHMSA integrity management requirements; consider seismicity in evaluating threats to a pipeline; conduct hydrostatic testing for all pipeline segments manufactured using longitudinal seam

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welds; and use more detailed guidance from PHMSA in the selection of assessment methods to inspect pipelines. The proposed rulemaking also seeks to impose a number of requirements on natural gas gathering lines. Issuance of the final rule remains pending. More recently, in January 2017, PHMSA finalized regulations for hazardous liquid pipelines that significantly extend and expand the reach of certain PHMSA integrity management requirements (i.e., periodic assessments, leak detection and repairs), regardless of the pipeline’s proximity to a high consequence area. The final rule would also impose new reporting requirements for certain unregulated pipelines, including all hazardous liquid gathering lines. However, PHMSA has delayed publication of the January 2017 rule in the federal register and, as a result, the rule has not yet become effective. The safety enhancement requirements and other provisions of the Pipeline Safety and Job Creation Act as well as any implementation of PHMSA rules thereunder could require us to install new or modified safety controls, pursue additional capital projects, or conduct maintenance programs on an accelerated basis, any or all of which tasks could result in our incurring increased operating costs that could have a material adverse effect on our results of operations or financial position.
Our ownership interest in White Cliffs could require us to make capital contributions from time to time, which could have a material adverse effect on our business, financial condition, results of operations, cash flows and ability to make distributions to our unitholders.
We currently own a 3.33% non-operating interest in White Cliffs. Because we do not operate or control White Cliffs, we do not have control over decisions to make maintenance and growth capital expenditures on the White Cliffs Pipeline. Furthermore, White Cliffs is subject to many of the same environmental and regulatory risks that our assets are subject to, including regulation by the FERC. To the extent that the operator of White Cliffs decides to make capital expenditures for White Cliffs or White Cliffs becomes subject to regulatory assessments, we could be required to contribute additional capital to White Cliffs, which could have a material adverse effect on our business, financial condition, results of operations, cash flows and ability to make distributions to our unitholders.
If third party pipelines or other facilities interconnected to our midstream systems become partially or fully unavailable, or if the volumes we gather or treat do not meet the quality requirements of such pipelines or facilities, our business, financial condition, results of operations, cash flows and ability to make distributions to our unitholders could be adversely affected.
Our midstream systems are connected to other pipelines or facilities, the majority of which are owned by third parties. The continuing operation of such third party pipelines or facilities is not within our control. If any of these pipelines or facilities becomes unable to transport, treat or process natural gas or crude oil, or if the volumes we gather or transport do not meet the quality requirements of such pipelines or facilities, our business, financial condition, results of operations, cash flows and ability to make distributions to our unitholders could be adversely affected.
Our exposure to commodity price risk may change over time and we cannot guarantee the terms of any existing or future agreements for our midstream services with our customers.
We currently generate the majority of our revenues pursuant to fee-based agreements under which we are paid based on volumetric fees, rather than the underlying value of the commodity. Consequently, our existing operations and cash flows have little direct exposure to commodity price risk. However, our customers are exposed to commodity price risk, and extended reduction in commodity prices could reduce the production volumes available for our midstream services in the future below expected levels. Although we intend to maintain fee-based pricing terms on both new contracts and existing contracts for which prices have not yet been set, our efforts to negotiate such terms may not be successful, which could have a materially adverse effect on our business.
Restrictions in our revolving 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 will 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 also contains covenants requiring us to maintain certain financial ratios.
The provisions of our revolving credit facility may affect our ability to obtain future financing and to pursue attractive business opportunities and our flexibility in planning for, and reacting to, changes in business conditions. In addition, a failure to comply with the provisions of our revolving credit facility could result in a default or an event of default that could enable our lenders to declare the outstanding principal of that debt, together with accrued and unpaid interest, to be immediately due and

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payable. If the payment of our debt is accelerated, our assets may be insufficient to repay such debt in full, and our unitholders could experience a partial or total loss of their investment. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources.
Increased regulation of hydraulic fracturing could result in reductions or delays in crude oil and natural gas production by our customers, which could reduce the throughput on our gathering and other midstream systems, which could adversely impact our revenues.
We do not conduct hydraulic fracturing operations, but substantially all of Noble’s crude oil and natural gas production on our dedicated acreage is developed from unconventional sources that require hydraulic fracturing as part of the completion process. The majority of our fresh water services business is related to the storage and transportation of water for use in hydraulic fracturing. Hydraulic fracturing is a well stimulation process that utilizes large volumes of water and sand combined with fracturing chemical additives that are pumped into a well at high pressure to crack open previously impenetrable rock to release hydrocarbons. Hydraulic fracturing is typically regulated by state oil and gas commissions and similar agencies. Some states and local governments, including those in which we operate, have adopted, and other states are considering adopting, regulations that could impose more stringent chemical disclosure or well construction requirements on hydraulic fracturing operations, or otherwise seek to ban some or all of these activities. Recently, however, several federal agencies have asserted jurisdiction over the process. For example, the EPA has moved forward with various regulatory actions, including the issuance of new regulations requiring green completions for hydraulically fractured wells, and emission requirements for certain midstream equipment. Also, in June 2016, the EPA finalized rules which prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants. Certain environmental groups have also suggested that additional laws may be needed to more closely and uniformly regulate the hydraulic fracturing process. We cannot predict whether any such legislation will be enacted and if so, what its provisions would be. Additional levels of regulation and permits required through the adoption of new laws and regulations at the federal, state or local level could lead to delays, increased operating costs and process prohibitions that could reduce the volumes of crude oil and natural gas that move through our gathering systems and decrease demand for our water services, which in turn could materially adversely impact our revenues.
We, Noble or any third party customers may incur significant liability under, or costs and expenditures to comply with, environmental and worker health and safety regulations, which are complex and subject to frequent change.
As an owner and operator of gathering systems, we are subject to various federal, state and local laws and regulations relating to the discharge of materials into, and protection of, the environment and worker health and safety. Numerous governmental authorities, such as the EPA and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring costly response actions. These laws and regulations may impose numerous obligations that are applicable to our and our customers’ operations, including the acquisition of permits to conduct regulated activities, the incurrence of capital or operating expenditures to limit or prevent releases of materials from our or our customers’ operations, the imposition of specific standards addressing worker protection, and the imposition of substantial liabilities and remedial obligations for pollution or contamination resulting from our and our customers’ operations. Failure to comply with these laws, regulations and permits may result in joint and several or strict liability or the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, or the issuance of injunctions or administrative orders limiting or preventing some or all of our operations. Private parties, including the owners of the properties through which our gathering systems pass, may also have the right to pursue legal actions to enforce compliance, as well as to seek damages for non-compliance, with environmental laws and regulations or for personal injury or property damage. We may not be able to recover all or any of these costs from insurance. In addition, we may experience a delay in obtaining or be unable to obtain required permits, which may cause us to lose potential and current customers, interrupt our operations or limit our growth and revenues, which in turn could affect the amount of cash we have available for distribution. We cannot provide any assurance that changes in or additions to public policy regarding the protection of the environment and worker health and safety will not have a significant impact on our operations and the amount of cash we have available for distribution.
Our operations also pose risks of environmental liability due to leakage, migration, releases or spills to surface or subsurface soils, surface water or groundwater. Certain environmental laws impose strict as well as joint and several liability for costs required to remediate and restore sites where hazardous substances, hydrocarbons or solid wastes have been stored or released. We may be required to remediate contaminated properties currently or formerly operated by us regardless of whether such contamination resulted from the conduct of others or from consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. In addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and safety impacts of our operations. Moreover, the trend of more expansive and stringent environmental legislation and regulations applied to the crude oil and natural gas industry could continue, potentially resulting in increased costs of doing business and consequently affecting the amount of cash we have available for distribution. See Items 1. and 2. Business and Properties – Regulation of Operations.

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Climate change laws and regulations restricting emissions of greenhouse gases could result in increased operating costs and reduced demand for the crude oil and natural gas that we gather while potential physical effects of climate change could disrupt Noble’s and our other customers’ production and cause us to incur significant costs in preparing for or responding to those effects.
In response to findings that emissions of carbon dioxide, methane and other greenhouse gases, or GHGs, present an endangerment to public health and the environment, the EPA has adopted regulations under existing provisions of the CAA that, among other things, establish PSD construction and Title V operating permit reviews for certain large stationary sources that emit GHGs. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards that will be established by the states or, in some cases, by the EPA on a case-by-case basis. These EPA rule makings could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore crude oil and natural gas production sources in the U.S. on an annual basis.
Climate and related energy policy, laws and regulations could change quickly, and substantial uncertainty exists about the nature of many potential developments that could impact the sources and uses of energy. In December 2015, the United States and 194 other participating countries adopted the Paris Agreement, which calls for each participating country to establish their own nationally determined standards for reducing carbon output. However, in August 2017 the United States notified the United Nations that it would be withdrawing from the Paris Agreement. Also, the EPA had previously finalized standards in June 2016 designed to reduce methane emissions from certain oil and gas facilities. However, in June 2017, the EPA published a proposed rule to stay certain portions of these 2016 standards for two years and reconsider the entirety of the 2016 standards. As a result of these actions, the 2016 methane standards are currently in effect but future implementation of the standards is uncertain at this time. Many states also are pursuing climate requirements either directly or indirectly through such measures as alternative fuel mandates. For example, in February 2014, Colorado’s Air Quality Control Commission approved comprehensive changes to rules governing crude oil and natural gas activities in the state, including the nation’s first-ever regulations designed to detect and reduce methane emissions. These measures may reduce the future demand for our products, particularly crude oil.
Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations. Substantial limitations on GHG emissions could also adversely affect demand for the crude oil and natural gas we gather. Recently, activists concerned about the potential effects of climate change have directed their attention at sources of funding for fossil-fuel energy companies, which has resulted in certain financial institutions, funds and other sources of capital restricting or eliminating their investment in oil and natural gas activities. Ultimately, this could make it more difficult to secure funding for energy infrastructure projects, such as pipelines and terminal facilities. Notwithstanding potential risks related to climate change, the International Energy Agency estimates that global energy demand will continue to rise and will not peak until after 2040 and that oil and gas will continue to represent a substantial percentage of global energy use over that time. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events; if any such effects were to occur, they could have an adverse effect on our operations or our customer’s exploration and production operations, which in turn could affect demand for our services. See Items 1. and 2. Business and Properties – Regulation of Operations.
Certain plant or animal species are or could be designated as endangered or threatened, which could have a material impact on our and Noble’s operations.
The ESA restricts activities that may affect endangered or threatened species or their habitats. Many states have analogous laws designed to protect endangered or threatened species. Such protections, and the designation of previously undesignated species under such laws, may affect our and Noble’s operations by imposing additional costs, approvals and accompanying delays.
A change in the jurisdictional characterization of some of our assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of our assets, which may cause our operating expenses to increase, limit the rates we charge for certain services and decrease the amount of cash we have available for distribution.
Although the FERC has not made a formal determination with respect to the facilities we consider to be natural gas gathering pipelines, we believe that our natural gas gathering pipelines meet the traditional tests that the FERC has used to determine that a pipeline is a gathering pipeline and are therefore not subject to FERC jurisdiction. The distinction between FERC-regulated transmission services and federally unregulated gathering services, however, has been the subject of substantial litigation, and the FERC determines whether facilities are gathering facilities on a case-by-case basis, so the classification and

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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.
In addition, certain of our crude oil gathering pipelines do not provide interstate services and therefore are not subject to regulation by the FERC pursuant to the ICA. The distinction between FERC-regulated crude oil interstate pipeline transportation, on the one hand, and crude oil intrastate pipeline transportation, on the other hand, also is a fact-based determination. The classification and regulation of these crude oil gathering pipelines are subject to change based on changed circumstances on the pipeline or on future determinations by the FERC, federal courts, Congress or by regulatory commissions, courts or legislatures in the states in which our crude oil gathering pipelines are located. We cannot provide assurance that the FERC will not in the future, either at the request of other entities or on its own initiative, determine that some or all of our gathering pipeline systems and the services we provide on those systems are within the FERC’s jurisdiction. If it is determined that some or all of our crude oil gathering pipeline systems are subject to the FERC’s jurisdiction under the ICA, and are not otherwise exempt from any applicable regulatory requirements, the imposition of possible cost-of-service rates and common carrier requirements on those systems could adversely affect the results of our operations on and revenues associated with those systems.
Our business involves many hazards and operational risks, some of which may not be fully covered by insurance. The occurrence of a significant accident or other event that is not fully insured could curtail our operations and have a material adverse effect on our ability to make cash distributions and, accordingly, the market price for our common units.
Our operations are subject to all of the hazards inherent in the gathering of crude oil, natural gas and produced water and the delivery and storage of fresh water, including:
damage to pipelines, centralized gathering facilities, pump stations, related equipment and surrounding properties caused by design, installation, construction materials or operational flaws, natural disasters, acts of terrorism or acts of third parties;
leaks of crude oil, natural gas or NGLs or losses of crude oil, natural gas or NGLs as a result of the malfunction of, or other disruptions associated with, equipment or facilities;
fires, ruptures and explosions; and
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.

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We may elect not to obtain insurance for any or all of these risks if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. The occurrence of an event that is not fully covered by insurance could have a material adverse effect on our business, financial condition, results of operations, cash flows and ability to make cash distributions.
We do not own in fee any of the land on which our pipelines and facilities are located, which could result in disruptions to our operations.
We do not own in fee any of the land on which our midstream systems have been constructed. Our only interests in these properties are rights granted under surface use agreements, rights-of-way, surface leases or other easement rights, which may limit or restrict our rights or access to or use of the surface estates. Accommodating these competing rights of the surface owners may adversely affect our operations. In addition, we are subject to the possibility of more onerous terms or increased costs to retain necessary land use if we do not have valid rights-of-way, surface leases or other easement rights or if such usage rights lapse or terminate. We may obtain the rights to construct and operate our pipelines on land owned by third parties and governmental agencies for a specific period of time. Our loss of these rights, through our inability to renew rights-of-way, surface leases or other easement rights or otherwise, could have a material adverse effect on our business, financial condition, results of operations, cash flows and ability to make cash distributions.
A shortage of equipment and skilled labor could reduce equipment availability and labor productivity and increase labor and equipment costs, which could have a material adverse effect on our business and results of operations.
Our gathering and other midstream services require special equipment and laborers who are skilled in multiple disciplines, such as equipment operators, mechanics and engineers, among others. If we experience shortages of necessary equipment or skilled labor in the future, our labor and equipment costs and overall productivity could be materially and adversely affected. If our equipment or labor prices increase or if we experience materially increased health and benefit costs for employees, our business and results of operations could be materially and adversely affected.
The loss of key personnel could adversely affect our ability to operate.
We depend on the services of a relatively small group of our General Partner’s senior management. We do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals. The loss of the services of our general partner’s senior management, including Terry R. Gerhart, our Chief Executive Officer, John F. Bookout, IV, our Chief Financial Officer, Thomas W. Christensen, our Chief Accounting Officer, and John C. Nicholson, our Chief Operating Officer could have a material adverse effect on our business, financial condition, results of operations, cash flows and ability to make cash distributions.
We do not have any officers or employees and rely on officers of our General Partner and employees of Noble.
We are managed and operated by the board of directors and executive officers of our General Partner. Our General Partner has no employees and relies on the employees of Noble to conduct our business and activities.
Noble conducts businesses and activities of its own in which we have no economic interest. As a result, there could be material competition for the time and effort of the officers and employees who provide services to both our General Partner and Noble. If our General Partner and the officers and employees of Noble do not devote sufficient attention to the management and operation of our business and activities, our business, financial condition, results of operations, cash flows and ability to make cash distributions could be materially adversely affected.
Debt we incur in the future may limit our flexibility to obtain financing and to pursue other business opportunities.
Our future level of debt could have important consequences to us, including the following:
our ability to obtain additional financing, if necessary, for working capital, capital expenditures (including building additional gathering pipelines needed for required connections and building additional centralized gathering facilities pursuant to our gathering agreements) or other purposes may be impaired or such financing may not be available on favorable terms;
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

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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, 2017, $85 million was outstanding under our revolving credit facility. If we assume an average debt level of $100 million, comprised of funds drawn on the revolving credit facility, an increase of one percentage point in the interest rates will result in an increase in annual interest expense of $1 million. As a result, our results of operations, cash flows and financial condition and, as a further result, our ability to make cash distributions to our unitholders, could be adversely affected by significant increases in interest rates.
Terrorist attacks or cyber-attacks could have a material adverse effect on our business, financial condition or results of operations.
Terrorist attacks or cyber-attacks may significantly affect the energy industry, including our operations and those of Noble and our other potential customers, as well as general economic conditions, consumer confidence and spending and market liquidity. Strategic targets, such as energy-related assets, may be at greater risk of future attacks than other targets in the United States. Our insurance may not protect us against such occurrences. Consequently, it is possible that any of these occurrences, or a combination of them, could have a material adverse effect on our business, financial condition and results of operations.
A cyber incident could result in information theft, data corruption, operational disruption and/or financial loss.
The oil and gas industry has become increasingly dependent on digital technologies to conduct day-to-day operations including certain midstream activities. For example, software programs are used to manage gathering and transportation systems and for compliance reporting. The use of mobile communication devices has increased rapidly. Industrial control systems such as SCADA (supervisory control and data acquisition) now control large scale processes that can include multiple sites and long distances, such as oil and gas pipelines.
We depend on digital technology, including information systems and related infrastructure as well as cloud applications and services, to process and record financial and operating data and to communicate with our employees and business partners. Our business partners, including vendors, service providers, and financial institutions, are also dependent on digital technology. The technologies needed to conduct midstream activities make certain information the target of theft or misappropriation.
As dependence on digital technologies has increased, cyber incidents, including deliberate attacks or unintentional events, also has increased. A cyber attack could include gaining unauthorized access to digital systems for purposes of misappropriating assets or sensitive information, corrupting data, or causing operational disruption, or result in denial-of-service on websites. SCADA-based systems are potentially vulnerable to targeted cyber attacks due to their critical role in operations.
Our technologies, systems, networks, and those of our business partners may become the target of cyber attacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or other disruption of our business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period.
A cyber incident involving our information systems and related infrastructure, or that of our business partners, could disrupt our business plans and negatively impact our operations in the following ways, among others:
a cyber attack on a vendor or service provider could result in supply chain disruptions which could delay or halt development of additional infrastructure, effectively delaying the start of cash flows from the project;
a cyber attack on downstream pipelines could prevent us from delivering product at the tailgate of our facilities, resulting in a loss of revenues;
a cyber attack on a communications network or power grid could cause operational disruption resulting in loss of revenues;
a deliberate corruption of our financial or operational data could result in events of non-compliance which could lead to regulatory fines or penalties; and
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.

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Risks Inherent in an Investment in Us
Our General Partner and its affiliates, including Noble, have conflicts of interest with us and our partnership agreement eliminates their default fiduciary duties to us and our unitholders and replaces them with contractual standards that may allow our General Partner and its affiliates to favor their own interests to our detriment and that of our unitholders. Additionally, we have no control over the business decisions and operations of Noble, and Noble is under no obligation to adopt a business strategy that favors us.
Noble directly owns an aggregate 45.5% limited partner interest in us. In addition, Noble owns and controls our General Partner. Although our General Partner has a duty to manage us in a manner that is not adverse to the interests of our partnership, the directors and officers of our General Partner also have a duty to manage our General Partner in a manner that is in the best interests of its owner, Noble. Conflicts of interest may arise between Noble and its affiliates, including our General Partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts, the General Partner may favor its own interests and the interests of its affiliates, including Noble, over the interests of our common unitholders. These conflicts include, among others, the following situations:
neither our partnership agreement nor any other agreement requires Noble to pursue a business strategy that favors us or utilizes our assets, which could involve decisions by Noble to increase or decrease crude oil or natural gas production on our dedicated acreage, pursue and grow particular markets or undertake acquisition opportunities for itself. Noble’s directors and officers have a fiduciary duty to make these decisions in the best interests of the stockholders of Noble;
Noble may be constrained by the terms of its debt instruments from taking actions, or refraining from taking actions, that may be in our best interests;
our partnership agreement replaces the fiduciary duties that would otherwise be owed by our General Partner with contractual standards governing its duties and limits our General Partner’s liabilities and the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty under applicable Delaware law;
except in limited circumstances, our General Partner has the power and authority to conduct our business without unitholder approval;
our General Partner will determine the amount and timing of, among other things, cash expenditures, borrowings and repayments of indebtedness, the issuance of additional partnership interests, the creation, increase or reduction in cash reserves in any quarter and asset purchases and sales, each of which can affect the amount of cash that is available for distribution to unitholders;
our General Partner will determine the amount and timing of any capital expenditures and whether a capital expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus. This determination can affect the amount of cash that is distributed to our unitholders and to our General Partner, the amount of adjusted operating surplus generated in any given period and the ability of the Subordinated Units to convert into Common Units;
our General Partner will determine which costs incurred by it are reimbursable by us;
our General Partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make a distribution on the Subordinated Units, to make incentive distributions or to accelerate expiration of the subordination period;
our partnership agreement permits us to distribute up to $45.0 million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources that would otherwise constitute capital surplus. This cash may be used to fund distributions on our Subordinated Units or to Noble in respect of the incentive distribution rights;
our partnership agreement does not restrict our General Partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf;
our General Partner intends to limit its liability regarding our contractual and other obligations;
our General Partner may exercise its right to call and purchase all of the common units not owned by it and its affiliates if it and its affiliates own more than 80% of the common units;
our General Partner controls the enforcement of obligations owed to us by our General Partner and its affiliates, including our gathering agreements with Noble, the ROFR and ROFO;
our General Partner decides whether to retain separate counsel, accountants or others to perform services for us; and

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Noble, or any transferee holding incentive distribution rights, may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to its incentive distribution rights, without the approval of the conflicts committee of the board of directors of our General Partner, which we refer to as our conflicts committee, or our common unitholders. This election could result in lower distributions to our common unitholders in certain situations.
Neither our partnership agreement nor our omnibus agreement will prohibit Noble or any other affiliates of our General Partner from owning assets or engaging in businesses that compete directly or indirectly with us. Under the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, will not apply to our General Partner or any of its affiliates, including Noble and executive officers and directors of our General Partner. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will not have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. Consequently, Noble and other affiliates of our General Partner may acquire, construct or dispose of additional midstream assets in the future without any obligation to offer us the opportunity to purchase any of those assets (except to the extent the ROFR or ROFO pertain to such assets). As a result, competition from Noble and other affiliates of our General Partner could materially and adversely impact our results of operations and distributable cash flow. This may create actual and potential conflicts of interest between us and affiliates of our General Partner and result in less than favorable treatment of us and our unitholders.
We expect to distribute a substantial portion of our cash available for distribution, which could limit our ability to grow and make acquisitions.
We expect to distribute most of our available cash for distribution. As a result, we expect to rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. Therefore, to the extent we are unable to finance our growth externally, our cash distribution policy will significantly impair our ability to grow. In addition, our growth may not be as fast as that of businesses that reinvest their cash to expand ongoing operations. To the extent we issue additional partnership interests in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional partnership interests may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no limitations in our partnership agreement on our ability to issue additional partnership interests, including partnership interests ranking senior to our common units as to distributions or in liquidation or that have special voting rights and other rights, and our common unitholders will have no preemptive or other rights (solely as a result of their status as common unitholders) to purchase any such additional partnership interests. The incurrence of additional commercial bank borrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn, may reduce the amount of cash that we have available to distribute to our unitholders.
Our partnership agreement replaces our General Partner’s fiduciary duties to holders of our common units with contractual standards governing its duties.
Delaware law provides that a Delaware limited partnership may, in its partnership agreement, expand, restrict or eliminate the fiduciary duties otherwise owed by the General Partner to limited partners and the partnership. As permitted by Delaware law, our partnership agreement contains provisions that eliminate the fiduciary standards to which our General Partner would otherwise be held by state fiduciary duty law and replaces those duties with several different contractual standards. For example, our partnership agreement permits our General Partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our General Partner, free of any duties to us and our unitholders. This entitles our General Partner to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our limited partners. By purchasing a common unit, a unitholder agrees to be bound by our partnership agreement and approves the elimination and replacement of fiduciary duties disclosed above.
Our partnership agreement restricts the remedies available to holders of our units and for actions taken by our General Partner that might otherwise constitute breaches of fiduciary duty.
Our partnership agreement contains provisions that restrict the remedies available to unitholders for actions taken by our General Partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our partnership agreement provides that:
whenever our General Partner makes a determination or takes, or declines to take, any other action in its capacity as our General Partner, our General Partner is required to make such determination, or take or decline to take such other action, in good faith, meaning that it subjectively believed that the determination or the decision to take or decline to take such action was not adverse to the interests of our partnership, and will not be subject to any other or different standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity;

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our General Partner will not have any liability to us or our unitholders for decisions made in its capacity as a General Partner so long as it acted in good faith;
our General Partner and its officers and directors will not be liable for monetary damages or otherwise to us or our limited partners resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our General Partner or its officers and directors, as the case may be, acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and
our General Partner will not be in breach of its obligations under our partnership agreement or its fiduciary duties to us or our limited partners if a transaction with an affiliate or the resolution of a conflict of interest is approved in accordance with, or otherwise meets the standards set forth in, our partnership agreement.
In connection with a situation involving a transaction with an affiliate or a conflict of interest, other than one where our General Partner is permitted to act in its sole discretion, our partnership agreement provides that any determination by our General Partner must be made in good faith. If an affiliate transaction or the resolution of a conflict of interest is not approved by our common unitholders or the conflicts committee, then it will be presumed that, in making its decision, taking any action or failing to act, the board of directors of our General Partner acted in good faith and in any proceeding brought by or on behalf of any limited partner or the Partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.
Cost reimbursements and fees due our General Partner and its affiliates for services provided will be substantial and will reduce the amount of cash we have available for distribution to unitholders.
Under our partnership agreement, we are required to reimburse our General Partner and its affiliates for all costs and expenses that they incur on our behalf for managing and controlling our business and operations. Except to the extent specified under our omnibus agreement and operational services and secondment agreement, our General Partner determines the amount of these expenses. Under the terms of the omnibus agreement, we will be required to reimburse Noble for the provision of certain administrative support services to us. Under our operational services and secondment agreement, we will be required to reimburse Noble for the provision of certain operation services and related management services in support of our operations. Our General Partner and its affiliates also may provide us other services for which we will be charged fees as determined by our General Partner. The costs and expenses for which we will reimburse our General Partner and its affiliates may include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our General Partner by its affiliates. The costs and expenses for which we are required to reimburse our General Partner and its affiliates are not subject to any caps or other limits. Payments to our General Partner and its affiliates will be substantial and will reduce the amount of cash we have available to distribute to unitholders.
Unitholders have very limited voting rights and, even if they are dissatisfied, they cannot remove our General Partner.
Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. For example, unlike holders of stock in a public corporation, unitholders will not have “say-on-pay” advisory voting rights. Unitholders did not elect our General Partner or the board of directors of our General Partner and will have no right to elect our General Partner or the board of directors of our General Partner on an annual or other continuing basis. The board of directors of our General Partner is chosen by its sole member, which is owned by Noble. Furthermore, if the unitholders are dissatisfied with the performance of our General Partner, they will have little ability to remove our General Partner. As a result of these limitations, the price at which our common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.
Our General Partner may not be removed unless such removal is both (i) for cause and (ii) approved by a vote of the holders of at least 66 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. Noble currently owns 45.5% of our total outstanding Common Units and Subordinated Units on an aggregate basis. As a result, our public unitholders do not have limited ability to remove our General Partner.
Furthermore, unitholders’ voting rights are further restricted by the partnership agreement provision providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our General Partner, its affiliates, their transferees, and persons who acquired such units with the prior approval of the board of directors of our General Partner, cannot vote on any matter.

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Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.
Our partnership agreement restricts the voting rights of certain unitholders owning 20% or more of our common units.
Unitholders’ voting rights are restricted by a provision of our partnership agreement providing that any person or group that owns 20% or more of any class of units then outstanding, other than our General Partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our General Partner, cannot vote on any matter.
Our General Partner interest or the control of our General Partner may be transferred to a third party without unitholder consent.
Our General Partner may transfer its General Partner interest in us to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, there is no restriction in our partnership agreement on the ability of Noble to transfer its membership interest in our General Partner to a third party. The new owner of our General Partner would then be in a position to replace the board of directors and officers of our General Partner with its own choices.
The incentive distribution rights held by Noble may be transferred to a third party without unitholder consent.
Noble may transfer our incentive distribution rights to a third party at any time without the consent of our unitholders. If Noble transfers our incentive distribution rights to a third party but retains its ownership of our General Partner interest, it may not have the same incentive to grow our partnership and increase quarterly distributions to unitholders over time as it would if it had retained ownership of our incentive distribution rights. For example, a transfer of incentive distribution rights by Noble could reduce the likelihood of Noble selling or contributing additional midstream assets to us, as Noble would have less of an economic incentive to grow our business, which in turn would impact our ability to grow our asset base.
We may issue an unlimited number of additional partnership interests without unitholder approval, which would dilute unitholder interests.
At any time, we may issue an unlimited number of General Partner interests or limited partner interests of any type without the approval of our unitholders and our unitholders will have no preemptive or other rights (solely as a result of their status as unitholders) to purchase any such General Partner interests or limited partner interests. Further, there are no limitations in our partnership agreement on our ability to issue equity securities that rank equal or senior to our common units as to distributions or in liquidation or that have special voting rights and other rights. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:
our unitholders’ proportionate ownership interest in us will decrease;
the amount of cash we have available to distribute on each unit may decrease;
the ratio of taxable income to distributions may increase;
the relative voting strength of each previously outstanding unit may be diminished; and
the market price of our common units may decline.
The issuance by us of additional General Partner interests may have the following effects, among others, if such General Partner interests are issued to a person who is not an affiliate of Noble:
management of our business may no longer reside solely with our current General Partner; and
affiliates of the newly admitted General Partner may compete with us, and neither that General Partner nor such affiliates will have any obligation to present business opportunities to us except with respect to rights of first refusal contained in our omnibus agreement.
Noble may sell units in the public or private markets, and such sales could have an adverse impact on the trading price of the common units.
Noble currently holds 2,090,014 common units and 15,902,584 Subordinated Units. All of the Subordinated Units will convert into common units at the end of the subordination period and may convert earlier under certain circumstances. Additionally, we have agreed to provide Noble with registration rights. The sale of these units in the public or private markets could have an adverse impact on the price of the common units or on any trading market that may develop.
Our General Partner’s discretion in establishing cash reserves may reduce the amount of cash we have available to distribute to unitholders.
Our partnership agreement requires our General Partner to deduct from operating surplus the cash reserves that it determines are necessary to fund our future operating expenditures. In addition, the partnership agreement permits the General Partner to

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reduce available cash by establishing cash reserves for the proper conduct of our business, to comply with applicable law or agreements to which we are a party, or to provide funds for future distributions to partners. These cash reserves will affect the amount of cash we have available to distribute to unitholders.
Affiliates of our General Partner, including Noble, may compete with us, and neither our General Partner nor its affiliates have any obligation to present business opportunities to us except with respect to dedications contained in our commercial agreements and rights of first refusal and rights of first offer contained in our omnibus agreement.
None of our partnership agreement, our omnibus agreement, our commercial agreements or any other agreement in effect will prohibit Noble or any other affiliates of our General Partner from owning assets or engaging in businesses that compete directly or indirectly with us. Under the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, will not apply to our General Partner or any of its affiliates, including Noble and executive officers and directors of our General Partner. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will not have any duty to communicate or offer such opportunity to us except with respect to dedications contained in our commercial agreements and rights of first refusal and rights of first offer contained in our omnibus agreement. Any such person or entity will not be liable to us or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. Consequently, Noble and other affiliates of our General Partner may acquire, construct or dispose of additional midstream assets in the future without any obligation to offer us the opportunity to purchase any of those assets. As a result, competition from Noble and other affiliates of our General Partner could materially and adversely impact our results of operations and distributable cash flow.
Our General Partner has a call right that may require our unitholders to sell their common units at an undesirable time or price.
If at any time our General Partner and its affiliates own more than 80% of our then-outstanding common units, our General Partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then current market price. As a result, our unitholders may be required to sell their common units at an undesirable time or price and may not receive any return on their investment. Our unitholders may also incur a tax liability upon a sale of their units. Our General Partner and its affiliates currently own approximately 8.8% of our common units (excluding any common units owned by the directors and executive officers of our General Partner and certain other individuals as selected by our General Partner under our directed unit program). At the end of the subordination period, assuming no additional issuances of common units by us (other than upon the conversion of the Subordinated Units), our General Partner and its affiliates will own approximately 45.5% of our outstanding common units.
Unitholders may have to repay distributions that were wrongfully distributed to them.
Under certain circumstances, unitholders may have to repay amounts wrongfully distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, or the Delaware Act, we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Liabilities to partners on account of their partnership interest and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.
Noble, or any transferee holding incentive distribution rights, may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to its incentive distribution rights, without the approval of our conflicts committee or our common unitholders. This election could result in lower distributions to our common unitholders in certain situations.
Noble, as the initial holder of our incentive distribution rights, has the right, at any time when there are no Subordinated Units outstanding and it has received distributions on its incentive distribution rights at the highest level to which it is entitled (50%) for each of the prior four consecutive fiscal quarters, to reset the initial target distribution levels at higher levels based on our distributions at the time of the exercise of the reset election. Following a reset election, the minimum quarterly distribution will be adjusted to equal the reset minimum quarterly distribution, and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution.
If Noble elects to reset the target distribution levels, it will be entitled to receive a number of common units. The number of common units to be issued to Noble will be equal to that number of common units that would have entitled their holder to an average aggregate quarterly cash distribution in the prior two quarters equal to the average of the distributions on the incentive distribution rights in such two quarters. We anticipate that Noble would exercise this reset right in order to facilitate

41


acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion. It is possible, however, that Noble could exercise this reset election at a time when it is experiencing, or expects to experience, declines in the cash distributions it receives related to its incentive distribution rights and may, therefore, desire to be issued common units rather than retain the right to receive distributions based on the initial target distribution levels. This risk could be elevated if our incentive distribution rights have been transferred to a third party. As a result, a reset election may cause our common unitholders to experience a reduction in the amount of cash distributions that they would have otherwise received had we not issued new common units in connection with resetting the target distribution levels. Additionally, Noble has the right to transfer all or any portion of our incentive distribution rights at any time, and such transferee will have the same rights as Noble relative to resetting target distributions if our General Partner concurs that the tests for resetting target distributions have been fulfilled.
Units held by persons who our General Partner determines are not “eligible holders” at the time of any requested certification in the future may be subject to redemption.
As a result of certain laws and regulations to which we are or may in the future become subject, we may require owners of our common units to certify that they are both U.S. citizens and subject to U.S. federal income taxation on our income. Units held by persons who our General Partner determines are not “eligible holders” at the time of any requested certification in the future may be subject to redemption. “Eligible holders” are limited partners whose (or whose owners’) (i) U.S. federal income tax status or lack of proof of U.S. federal income tax status does not have and is not reasonably likely to have, as determined by our General Partner, a material adverse effect on the rates that can be charged to customers by us or our subsidiaries with respect to assets that are subject to regulation by the FERC or similar regulatory body and (ii) nationality, citizenship or other related status does not create and is not reasonably likely to create, as determined by our General Partner, a substantial risk of cancellation or forfeiture of any property in which we have an interest. The aggregate redemption price for redeemable interests will be an amount equal to the current market price (the date of determination of which will be the date fixed for redemption) of limited partner interests of the class to be so redeemed multiplied by the number of limited partner interests of each such class included among the redeemable interests. For these purposes, the “current market price” means, as of any date for any class of limited partner interests, the average of the daily closing prices per limited partner interest of such class for the 20 consecutive trading days immediately prior to such date. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our General Partner. The units held by any person the General Partner determines is not an eligible holder will not be entitled to voting rights.
Our partnership agreement will designate the Court of Chancery of the State of Delaware as the exclusive forum for certain types of actions and proceedings that may be initiated by our unitholders, which would limit our unitholders’ ability to choose the judicial forum for disputes with us or our General Partner’s directors, officers or other employees. Our partnership agreement also provides that any unitholder bringing an unsuccessful action will be obligated to reimburse us for any costs we have incurred in connection with such unsuccessful action.
Our partnership agreement 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.
If any person brings any of the aforementioned claims, suits, actions or proceedings (including any claims, suits, actions or proceedings arising out of this offering) and such person does not obtain a judgment on the merits that substantially achieves, in substance and amount, the full remedy sought, then such person shall be obligated to reimburse us and our affiliates for all fees, costs and expenses of every kind and description, including but not limited to all reasonable attorneys’ fees and other litigation expenses, that the parties may incur in connection with such claim, suit, action or proceeding. In addition, our partnership agreement provides that each limited partner irrevocably waives the right to trial by jury in any such claim, suit, action or proceeding. By purchasing a common unit, a limited partner is irrevocably consenting to these limitations and provisions regarding claims, suits, actions or proceedings and submitting to the exclusive jurisdiction of the Court of Chancery of the State of Delaware (or such other court) in connection with any such claims, suits, actions or proceedings. These provisions may have the effect of discouraging lawsuits against us and our General Partner’s directors and officers.



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The NYSE does not require a publicly traded limited partnership like us to comply with certain of its corporate governance requirements.
Our common units are listed on the NYSE. Because we are a publicly traded limited partnership, the NYSE does not require us to have a majority of independent directors on our General Partner’s board of directors or to establish a compensation committee or a nominating and corporate governance committee. Additionally, any future issuance of additional common units or other securities, including to affiliates, will not be subject to the NYSE’s shareholder approval rules that apply to a corporation. Accordingly, unitholders will not have the same protections afforded to certain corporations that are subject to all of the NYSE corporate governance requirements.
If we fail to establish and maintain effective internal control over financial reporting, our ability to accurately report our financial results could be adversely affected.
We are required to comply with the SEC’s rules implementing Sections 302 and 404 of the Sarbanes-Oxley Act of 2002, which requires our management to certify financial and other information in our quarterly and annual reports and provide an annual management report on the effectiveness of our internal control over financial reporting.
If we fail to develop or maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential unitholders could lose confidence in our financial reporting, which would harm our business and the trading price of our units.
Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public company. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed. We cannot be certain that our efforts to develop and maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002. Any failure to develop or maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our units.
If we are deemed an “investment company” under the Investment Company Act of 1940, it would adversely affect the price of our common units and could have a material adverse effect on our business.
Our assets consist of direct and indirect ownership interests in our DevCos as well as ownership interests in other midstream ventures. If a sufficient amount of our assets, such as our ownership interests in other midstream ventures, now owned or in the future acquired, are deemed to be “investment securities” within the meaning of the Investment Company Act of 1940, or the Investment Company Act, we would either have to register as an investment company under the Investment Company Act, obtain exemptive relief from the SEC or modify our organizational structure or our contract rights to fall outside the definition of an investment company. In that event, it is possible that our ownership of these interests, combined with our assets acquired in the future, could result in our being required to register under the Investment Company Act if we were not successful in obtaining exemptive relief or otherwise modifying our organizational structure or applicable contract rights. Treatment of us as an investment company would prevent our qualification as a partnership for federal income tax purposes in which case we would be treated as a corporation for federal income tax purposes. As a result, we would pay federal income tax on our taxable income at the corporate tax rate, distributions to our unitholders would generally be taxed again as corporate distributions and none of our income, gains, losses or deductions would flow through to our unitholders. Because a tax would be imposed upon us as a corporation, our cash available for distribution to unitholders would be substantially reduced. Therefore, treatment of us as an investment company would result in a material reduction in the anticipated cash flow and after-tax return to the unitholders, likely causing a substantial reduction in the value of our common units.
Moreover, registering as an investment company could, among other things, materially limit our ability to engage in transactions with affiliates, including the purchase of additional interests in our midstream systems from Noble, restrict our 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.


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Tax Risks
Our tax treatment depends on our status as a partnership for federal income tax purposes. If the Internal Revenue Service (IRS) were to treat us as a corporation for federal income tax purposes, which would subject us to entity-level taxation, or if we were otherwise subjected to a material amount of entity-level taxation, then our distributable cash flow to our unitholders would be substantially reduced.
The anticipated after-tax economic benefit of an investment in the common units depends largely on our being treated as a partnership for federal income tax purposes.
Despite the fact that we are organized as a limited partnership under Delaware law, we would be treated as a corporation for federal income tax purposes unless we satisfy a “qualifying income” requirement. Based upon our current operations, we believe we satisfy the qualifying income requirement. Failing to meet the qualifying income requirement or a change in current law could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.
If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate and we would also likely pay additional state and local income taxes at varying rates. Distributions would generally be taxed again as corporate dividends (to the extent of our current and accumulated earnings and profits), and no income, gains, losses, deductions, or credits would flow through to our unitholders. Because a tax would be imposed upon us as a corporation, our distributable cash flow would be substantially reduced.
At the state level, several states have been evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of a material amount of any of these taxes in the jurisdictions in which we own assets or conduct business could substantially reduce the cash available for distribution to our unitholders.
If we were treated as a corporation for federal income tax purposes or otherwise subjected to a material amount of entity-level taxation, there would be a material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our common units.
Our partnership agreement provides that, if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution levels may be adjusted to reflect the impact of that law or interpretation on us.
The tax treatment of publicly traded partnerships or an investment in our units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.
The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time. From time to time, members of Congress have proposed and considered substantive changes to the existing federal income tax laws that would affect publicly traded partnerships, including elimination of partnership tax treatment for publicly traded partnerships.
We are unable to predict whether any of these changes or proposals will ultimately be enacted. Any modification to the federal income tax laws and interpretations thereof may or may not be retroactively applied and could make it more difficult or impossible for us to meet the exception to be treated as a partnership for federal income tax purposes and could negatively impact the value of an investment in our common units.
Further, Treasury Regulations under Section 7704(d)(1)(E) of the Internal Revenue Code that apply to taxable years beginning on or after January 19, 2017 interpret the scope of qualifying income requirements for publicly traded partnerships by providing industry-specific guidance. We believe the income that we treat as qualifying satisfies the requirements under these regulations. However, there are no assurances that the regulations will not be revised to take a position that is contrary to our interpretation of current law.
You are urged to consult with your own tax advisor with respect to the status of regulatory or administrative developments and proposals and their potential effect on your investment in our common units.
If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and our cash available to our unitholders might be substantially reduced.
The IRS may adopt positions that differ from the conclusions of our counsel expressed in this Annual Report or from the positions we take, and the IRS’s positions may ultimately be sustained. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel’s conclusions or the positions we take and such positions may not ultimately be sustained. A court may not agree with some or all of our counsel’s conclusions or the positions we take. Any contest with the IRS, and the outcome of any IRS contest, may materially and adversely impact on the market for our common units and the

44


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 audit adjustments to our partnership tax returns, to the extent possible under the new rules our General Partner may elect to either pay the taxes (including any applicable penalties and interest) directly to the IRS in the year in which the audit is completed or, if we are eligible, issue a revised information statement to each unitholder and former unitholder with respect to an audited and adjusted partnership tax return. Although our General Partner may elect to have our unitholders and former unitholders take such audit adjustment into account and pay any resulting taxes (including applicable penalties or interest) in accordance with their interests in us during the tax year under audit, there can be no assurance that such election will be practical, permissible or effective in all circumstances. If we make payments of taxes and any penalties and interest directly to the IRS in the year in which the audit is completed, our 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 unitholders did not own units in us during the tax year under audit.
Our unitholders’ share of our income is taxable to them for federal income tax purposes even if they do not receive any cash distributions from us.
Each unitholder is treated as a partner to whom we will allocate taxable income even if the unitholder does not receive any cash distributions from us. Unitholders are required to pay federal income taxes and, in some cases, state and local income taxes, on their share of our taxable income, whether or not they receive cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax due from them with respect to that income.
Tax gain or loss on the disposition of our common units could be more or less than expected.
If our unitholders sell common units, they will recognize a gain or loss for federal income tax purposes equal to the difference between the amount realized and their tax basis in those common units. Because distributions in excess of their allocable share of our net taxable income decrease their tax basis in their common units, the amount, if any, of such prior excess distributions with respect to the common units a unitholder sells will, in effect, become taxable income to the unitholder if it sells such common units at a price greater than its tax basis in those common units, even if the price received is less than its original cost. Furthermore, a substantial portion of the amount realized on any sale of common units, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. Thus, a unitholder may recognize both ordinary income and capital loss from the sale of common units if the amount realized on a sale of the common units is less than the unitholder’s adjusted basis in common units. In addition, because the amount realized includes a unitholder’s share of our non-recourse liabilities, a unitholder that sells common units may incur a tax liability in excess of the amount of cash received from the sale.
Unitholders may be subject to limitations on their ability to deduct interest expense we incur.
Our ability to deduct business interest expense will be limited for federal income tax purposes to an amount equal to our business interest income and 30% of our “adjusted taxable income” during the taxable year computed without regard to any business interest income or expense, and in the case of taxable years beginning before 2022, any deduction allowable for depreciation, amortization, or depletion. Business interest expense that we are not entitled to fully deduct will be allocated to each unitholder as excess business interest and can be carried forward by the unitholder to successive taxable years and used to offset any excess taxable income allocated by us to the unitholder. Any excess business interest expense allocated to a unitholder will reduce the unitholder’s tax basis in its partnership interest in the year of the allocation even if the expense does not give rise to a deduction to the unitholder in that year.
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 federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. With respect to taxable years beginning after December 31, 2017, a tax-exempt entity with more than one unrelated trade or business cannot aggregate losses from one unrelated trade or business to offset income from another to reduce total unrelated business taxable income. As a result, for the years beginning after December 31, 2017, it may not be possible for tax-exempt

45


entities to utilize losses from an investment in us to offset unrelated business taxable income from another unrelated trade or business and vice versa. Tax exempt entities should consult a tax advisor before investing in our Common Units.
Non-U.S. unitholders will be subject to federal income taxes and withholding with respect to income and gain from owning our common units.
Non-U.S. persons are generally taxed and subject to federal income tax filing requirements on income effectively connected with a U.S. trade or business. Income allocated to our unitholders and, under recently enacted legislation, any gain from the sale of our 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. persons will be required unitholder who sells or otherwise disposes of a common unit will also be subject to file federal income tax returns and pay tax on their share of our taxable income on the gain realized from the sale or disposition of that unit.
Recently enacted legislation also imposes a federal income tax withholding obligation of 10% of the amount realized upon a non-U.S. person’s sale or exchange of an interest in a partnership that is engaged in a U.S. trade or business. However, due to challenges of administering a withholding obligation applicable to open market trading and other complications, the application of this withholding rule to dispositions of publicly traded partnership interests has been temporarily suspended by the IRS until regulations or other guidance that resolves the challenges have been issued. It is not clear if or when such regulations or guidance will be issued. Non-U.S. persons should consult a tax advisor before investing in our Common Units.
We treat each purchaser of Common Units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.
Because we cannot match transferors and transferees of common units and because of other reasons, our depreciation and amortization positions may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to unitholders. It also could affect the timing of these tax benefits or the amount of gain from a unitholder’s sale of common units and could have a negative impact on the value of our common units or result in tax return audit adjustments.
We prorate our items of income, gain, loss and deduction for federal income tax purposes between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.
We generally prorate our items of income, gain, loss and deduction for federal income tax purposes between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. Although Treasury Regulations allow publicly traded partnerships to use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders, these Treasury Regulations do not specifically authorize all aspects of our proration method. If the IRS were to successfully challenge our proration method, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.
A unitholder whose common units are loaned to a “short seller” to effect a short sale of common units may be considered as having disposed of those common units. If so, the unitholder would no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition.
Because there are no specific rules governing the U.S. federal income tax consequence of loaning a partnership interest, a unitholder whose common units are loaned to a “short seller” to effect a short sale of common units may be considered as having disposed of the loaned common units, the unitholder may no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those common units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those common units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to consult a tax advisor to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from loaning their common units.



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We have adopted certain valuation methodologies in determining a unitholder’s allocations of income, gain, loss and deduction. The IRS may challenge these methodologies or the resulting allocations, and such a challenge could adversely affect the value of our common units.
In determining the items of income, gain, loss and deduction allocable to our unitholders, in certain circumstances, including when we issue additional units, we must determine the fair market value of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we make many fair market value estimates ourselves using a methodology based on the market value of our common units as a means to determine the fair market value of our assets. The IRS may challenge these valuation methods and the resulting allocations of income, gain, loss and deduction for federal income tax purposes.
A successful IRS challenge to these methods or allocations could adversely affect the amount, character and timing of our taxable income or loss and a unitholder’s distributive share of these items. It also could affect the amount of gain from our unitholders’ sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to our items of income, gain, loss and deduction and a unitholder’s distributive share of these items without the benefit of additional deductions.
As a result of investing in our common units, our unitholders may become subject to state and local taxes and return filing requirements in jurisdictions where we operate or own or acquire properties.
In addition to 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.

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

Item 4.  Mine Safety Disclosures
Not Applicable.

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PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Our common units are listed on the NYSE and traded under the symbol “NBLX.” As of December 31, 2017, our common units were held by 33 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, 2017, Noble owned 2,090,014 of our Common Units and 15,902,584 of our Subordinated Units, which together represent a 45.5% limited partner interest in us.
The following table sets forth the range of high and low sales prices per common unit as reported on the NYSE and the cash distributions per unit declared on the common units from the closing of our IPO through December 31, 2017:
 
Common Unit Price
 
Quarterly Cash Distribution per Unit (1)
 
High
 
Low
 
2016
 
 
 
 
 
Third Quarter (2)
$
28.14

 
$
26.00

 
$

Fourth Quarter (3)
40.16

 
26.92

 
0.4333

2017
 
 
 
 
 
First Quarter
$
53.29

 
$
35.56

 
$
0.4108

Second Quarter
52.82

 
41.90

 
0.4457

Third Quarter
56.33

 
42.12

 
0.4665

Fourth Quarter
$
52.72

 
$
47.06

 
$
0.4883

(1) 
Represents cash distribution attributable to the quarter and declared and paid within 45 days of quarter end pursuant to the terms of our partnership agreement. See Distributions of Available Cash, below.
(2) 
Period begins September 15, 2016, the commencement date of trading of the common units.
(3) 
The distribution for the fourth quarter of 2016 is comprised of $0.3925 per unit for the fourth quarter 2016 and $0.0408 per unit for the 10-day period beginning on the closing of the IPO on September 20, 2016 and ending on September 30, 2016.
Securities Authorized for Issuance Under Equity Compensation Plans 
In connection with the completion of the IPO, the board of directors of our General Partner adopted the Noble Midstream Partners LP 2016 Long-Term Incentive Plan (the LTIP), which permits the issuance of up to 1,860,000 common units. See Item 8. Financial Statements and Supplementary Data – Note 10. Unit-Based Compensation and Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters for information regarding our equity compensation plan as of December 31, 2017.
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 25, 2018, the board of directors of our General Partner declared a quarterly cash distribution of $0.4883 per limited partner unit. The distribution was paid on February 12, 2018, to unitholders of record on February 5, 2018. Also on February 12, 2018, a cash distribution of $0.5 million will be made to Noble related to its Incentive Distribution Rights (IDRs), based upon the level of distribution paid per Common and Subordinated Unit.
Definition of Available Cash
Available cash generally means, for any quarter, all cash and cash equivalents on hand at the end of that quarter:
less, the amount of cash reserves established by our General Partner to:
provide for the proper conduct of our business (including reserves for our future capital expenditures, future acquisitions and for anticipated future credit needs);
comply with applicable law or any loan agreement, security agreement, mortgage, debt instrument or other agreement or obligation to which we or any of our subsidiaries is a party or by which we or such subsidiary is bound or we or such subsidiary’s assets are subject; or
provide funds for distributions to our unitholders and to our General Partner for any one or more of the next four quarters (provided that our general partner may not establish cash reserves for distributions pursuant to this

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bullet point if the effect of such reserves will prevent us from distributing the minimum quarterly distribution on all common units and any cumulative arrearages on such common units for the current quarter);
plus, if our General Partner so determines, all or any portion of the cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made subsequent to the end of such quarter.
The purpose and effect of the last bullet point above is to allow our General Partner, if it so decides, to use cash from working capital borrowings made after the end of the quarter but on or before the date of determination of available cash for that quarter to pay distributions to unitholders. Under our partnership agreement, working capital borrowings are generally borrowings incurred under a credit facility, commercial paper facility or similar financing arrangement that are used solely for working capital purposes or to pay distributions to our partners and with the intent of the borrower to repay such borrowings within twelve months with funds other than from additional working capital borrowings.
Intent to Distribute the Minimum Quarterly Distribution
Under our current cash distribution policy, we intend distribute at least the minimum quarterly distribution of $0.375 per unit, or $1.50 per unit on an annualized basis, to the holders of our Common and Subordinated Units to the extent we have sufficient available cash after the establishment of cash reserves and the payment of costs and expenses, including reimbursements of expenses to our General Partner. We expect that if we are successful in executing our business strategy, we will grow our business in a steady and sustainable manner and distribute to our unitholders a portion of any increase in our cash available for distribution resulting from such growth. We expect our General Partner may cause us to establish reserves for specific purposes, such as major capital expenditures or debt service payments, or may choose to generally reserve cash in the form of excess distribution coverage from time to time for the purpose of maintaining stability or growth in our quarterly distributions. In addition, our General Partner may cause us to borrow amounts to fund distributions in quarters when we generate less cash than is necessary to sustain or grow our cash distributions per unit. Our cash distribution policy reflects a judgment that our unitholders will be better served by our distributing rather than retaining our cash available for distribution. However, there is no guarantee that we will pay the minimum quarterly distribution or any other amount of distributions on our units in any quarter. The amount of distributions paid under our cash distribution policy and the decision to make any distribution will be determined by our General Partner.
General Partner Interest
Our General Partner owns a non-economic General Partner interest in us, which does not entitle it to receive cash distributions. However, our General Partner may in the future own common units or other equity securities in us that will entitle it to receive distributions.
Incentive Distribution Rights
Noble currently holds IDRs that entitle it to receive increasing percentages, up to a maximum of 50%, of the available cash we distribute from operating surplus in excess of $0.4313 per unit per quarter. The maximum distribution of 50% does not include any distributions that Noble may receive on common units or Subordinated Units that it owns.
Percentage Allocations of Available Cash from Operating Surplus
The following table illustrates the percentage allocations of available cash from operating surplus between the unitholders and our General Partner based on the specified target distribution levels. The amounts set forth under “Marginal Percentage Interest in Distributions” are the percentage interests of Noble, as holder of our IDRs, and the unitholders in any available cash from operating surplus we distribute up to and including the corresponding amount in the column “Total Quarterly Distribution Per Unit.” The percentage interests shown for our unitholders and Noble for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests set forth below assume that Noble has not transferred its IDRs and that there are no arrearages on common units.
 
 
Marginal Percentage Interest in Distributions
 
Total Quarterly Distribution Per Unit
Unitholders
IDR Holders
Minimum Quarterly Distribution
$0.3750
100
%
%
First Target Distribution
above $0.3750 up to $0.4313
100
%
%
Second Target Distribution
above $0.4313 up to $0.4688
85
%
15
%
Third Target Distribution
above $0.4688 up to $0.5625
75
%
25
%
Thereafter
above $0.5625
50
%
50
%


49


Subordinated Units and Subordination Period
Our partnership agreement provides that, during the subordination period, the common units have the right to receive distributions of available cash from operating surplus each quarter in an amount equal to the minimum quarterly distribution, plus any arrearages in the payment of the minimum quarterly distribution on the Common Units from prior quarters, before any distributions of available cash from operating surplus may be made on the Subordinated Units. No arrearages will accrue or be payable on the Subordinated Units.
When the subordination period ends, each outstanding Subordinated Unit will convert into one Common Unit and will thereafter participate pro rata with the other Common Units in distributions of available cash.
Subordinated Units
Noble owns 15,902,584 Subordinated Units, which represents all of our Subordinated Units.
Definition of Subordination Period
The subordination period will end on the first business day following the distribution of available cash in respect of any quarter beginning after September 30, 2019 that each of the following tests are met:
distributions of available cash from operating surplus on each of the outstanding common units and Subordinated Units equaled or exceeded $1.50 (the annualized minimum quarterly distribution), for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date;
the adjusted operating surplus generated during each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of $1.50 (the annualized minimum quarterly distribution) on all of the outstanding common units and Subordinated Units during those periods on a fully diluted basis; and
there are no arrearages in payment of the minimum quarterly distribution on the Common Units.
Early Termination of the Subordination Period
Notwithstanding the foregoing, the subordination period will automatically terminate on the first business day following the distribution of available cash in respect of any quarter, beginning with the quarter ending September 30, 2017, that each of the following tests are met:
distributions of available cash from operating surplus on each of the outstanding Common Units and Subordinated Units equaled or exceeded $2.25 (150% of the annualized minimum quarterly distribution), for the four-quarter period immediately preceding that date;
the adjusted operating surplus generated during the four-quarter period immediately preceding that date equaled or exceeded the sum of (i) $2.25 (150% of the annualized minimum quarterly distribution) on all of the outstanding Common Units and Subordinated Units during that period on a fully diluted basis and (ii) the corresponding distributions on the incentive distribution rights; and
there are no arrearages in payment of the minimum quarterly distribution on the common units.

50


Item 6. Selected Financial Data
Selected Financial Data for periods prior to September 20, 2016 represent the Contributed Businesses of certain of Noble’s midstream assets as the accounting Predecessor to the Partnership, presented on a carve-out basis of Noble’s historical ownership of the Predecessor. The Predecessor financial data has been prepared from the separate records maintained by Noble and may not necessarily be indicative of the actual results of operations that might have occurred if the Predecessor had been operated separately during the periods reported. The information presented below should be read in conjunction with the information in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and the consolidated financial statements and related notes appearing in Item 8. Financial Statements and Supplementary Data.
 
Year Ended December 31,
(thousands, except as noted)
2017
 
2016
 
2015
 
2014
Statements of Operations
 
 
 
 
 
 
 
Total Revenues
$
239,281

 
$
160,724

 
$
87,837

 
$
2,086

Net Income
163,636

 
85,502

 
38,042

 
(15,091
)
Net Income Attributable to Noble Midstream Partners LP
140,572

 
28,458

 
N/A
 
N/A
 
 
 
 
 
 
 
 
Net Income Attributable to Limited Partners Per Limited Partner Unit  Basic and Diluted
 
 
 
 
 
 
 
Common Units
$
4.10

 
$
0.89

 
N/A
 
N/A
Subordinated Units
4.10

 
0.89

 
N/A
 
N/A
Cash Distributions Declared per Limited Partner Unit
1.8113

 
0.4333

 
N/A
 
N/A
 
 
 
 
 
 
 
 
Balance Sheet
 
 
 
 
 
 
 
Cash and Cash Equivalents
$
18,026

 
$
57,421

 
$
26,612

 
$

Total Property, Plant and Equipment, Net
661,768

 
279,403

 
250,933

 
195,513

Total Assets
829,758

 
369,359

 
305,318

 
216,512

Long-Term Debt
85,000

 

 

 

Total Liabilities
213,528

 
26,454

 
41,779

 
2,839

Total Equity
616,230

 
342,905

 
263,539

 
213,673

 
 
 
 
 
 
 
 
Cash Flows
 
 
 
 
 
 
 
Net Cash Provided by (Used in) Operating Activities
$
166,225

 
$
118,451

 
$
69,394

 
$
(12,534
)
Net Cash Used in Investing Activities
(380,945
)
 
(38,137
)
 
(54,461
)
 
(79,904
)
Net Cash Provided by (Used in) Financing Activities
175,325

 
(49,505
)
 
11,679

 
92,438

 
 
 
 
 
 
 
 
Non-GAAP Financial Measures(1)
 
 
 
 
 
 
 
Adjusted EBITDA
$
179,002

 
$
126,271

 
$
72,754

 
$
(9,388
)
Adjusted EBITDA Attributable to Noble Midstream Partners LP
154,509

 
30,697

 
N/A
 
N/A
Distributable Cash Flow of Noble Midstream Partners LP
137,935

 
28,425

 
N/A
 
N/A
 
 
 
 
 
 
 
 
Throughput Volumes
 
 
 
 
 
 
 
Crude Oil Gathering Volumes (Bbl/d)
65,655

 
45,236

 
33,977

 
16,522

Natural Gas Gathering Volumes (MMBtu/d)
180,918

 
132,147

 
86,103

 
71,137

Crude Oil and Natural Gas Gathering Volumes (MBoe/d)
89

 
62

 
45

 
26

Produced Water Gathering Volumes (Bbl/d)
24,431

 
10,592

 
5,198

 
5,422

Fresh Water Services Volumes (Bbl/d)
155,990

 
94,227

 
51,980

 
43,797

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

51


Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) is intended to provide a narrative about our business from the perspective of our management. Our MD&A is presented in the following major sections:
Predecessor  This Annual Report on Form 10-K includes the assets, liabilities and results of operations of the Contributed Businesses on a carve-out basis (our Predecessor for accounting purposes) for periods prior to September 20, 2016, the date on which we completed the IPO. Our future results of operations may not be comparable to our Predecessor’s historical results of operations.
MD&A is the Partnership’s analysis of its financial performance and of significant trends that may affect future performance. It should be read in conjunction with the consolidated financial statements and related notes appearing elsewhere in this report. It contains forward-looking statements including, without limitation, statements relating to the Partnership’s plans, strategies, objectives, expectations and intentions. The words “anticipate,” “estimate,” “believe,” “budget,” “continue,” “could,” “intend,” “may,” “plan,” “potential,” “predict,” “seek,” “should,” “will,” “would,” “expect,” “objective,” “projection,” “forecast,” “goal,” “guidance,” “outlook,” “effort,” “target”, “on schedule”, “strategy” and similar expressions identify forward-looking statements. The Partnership does not undertake to update, revise or correct any of the forward-looking information unless required to do so under the federal securities laws. Readers are cautioned that such forward-looking statements should be read in conjunction with the Partnership’s disclosures under “Disclosure Regarding Forward-Looking Statements” in this Form 10-K.
EXECUTIVE OVERVIEW
Overview
We are a growth-oriented Delaware master limited partnership formed in December 2014 by our Parent, Noble, to own, operate, develop and acquire a wide range of domestic midstream infrastructure assets. Our current areas of focus are in the DJ Basin in Colorado and the Delaware Basin in Texas. We currently provide crude oil, natural gas, and water-related midstream services through long-term, fixed-fee contracts. Our business activities are conducted through three reportable segments: Gathering Systems (crude oil, natural gas and produced water gathering as well as crude oil treating), Fresh Water Delivery, and Investments and Other. We often refer to the services of our Gathering Systems and Fresh Water Delivery reportable segments collectively as our midstream services.
We are Noble’s primary vehicle for its midstream operations in the onshore United States. We believe that our diverse midstream infrastructure assets and our relationship with Noble position us as a leading midstream service provider.
Significant Results
The following discussion highlights significant operating, transactional and financial results for the year ended December 31, 2017.
Significant Operational Highlights Included:
average crude oil gathering volumes of 65.7 MBbl/d;
average natural gas gathering volumes of 180.9 BBtu/d;
average produced water gathering volumes of 24.4 MBbl/d;
average fresh water delivery volumes of 156.0 MBbl/d;
completion of a produced water expansion project in the Wells Ranch CGF;
completion of construction and commencement of crude oil gathering, produced water gathering and fresh water delivery services to an unaffiliated third party in the Greeley Crescent IDP;
completion of construction of the Billy Miner I and Jesse James CGFs in the Delaware Basin;
commencement of crude oil, natural gas and produced water gathering services in the Delaware Basin; and
completion of construction of the connection from our CGFs in the Delaware Basin to the Advantage Pipeline.

52


Significant Transactional Highlights Included:
completion of the Advantage acquisition through the Advantage Joint Venture;
acquisition of the remaining 20% limited partner interest in Colorado River DevCo LP and an additional 15% limited partner interest in Blanco River DevCo LP from Noble;
completion of the Private Placement for gross proceeds of approximately $142.6 million and net proceeds of approximately $138.0 million;
completion of the Unit Offering for gross proceeds of approximately $174.8 million and net proceeds of $174.1 million; and
entrance into the Acquisition Agreement with Greenfield Member to acquire Saddle Butte for approximately $638.5 million, subject to customary adjustments following closing.
Significant Financial Highlights Included:
net income of $163.6 million, of which $140.6 million is attributable to the Partnership;
cash distributions declared of $0.4108 per unit for first quarter 2017 and paid during second quarter 2017;
cash distributions declared of $0.4457 per unit for second quarter 2017 and paid during third quarter 2017;
cash distributions declared of $0.4665 per unit for third quarter 2017 and paid during fourth quarter 2017
cash distributions declared of $0.4883 per unit for fourth quarter 2017;
net cash provided by operating activities of $166.2 million;
capital expenditures, excluding additions to investments and on an accrual basis, of $390.3 million;
Adjusted EBITDA (non-GAAP financial measure) of $179.0 million, of which $154.5 million is attributable to the Partnership; and
distributable cash flow (non-GAAP financial measure) of $137.9 million.

OPERATING OUTLOOK
2018 Capital Investment Program
Our preliminary 2018 capital investment program will accommodate a gross investment level of approximately $485 to $535 million, with $255 to $285 million attributable to the Partnership. We will evaluate the level of capital spending throughout the year based on the following factors, among others, and their effect on project financial returns: 
pace of our customers’ development;
operating and construction costs and our ability to achieve material supplier price reductions;
impact of new laws and regulations on our business practices;
indebtedness levels; and
availability of financing or other sources of funding.
We plan to fund our investment program with cash on hand, from cash generated from operations, borrowings under our revolving credit facility and, if necessary, the issuance of additional equity or debt securities.
Dedication and ROFR Update
On April 24, 2017, Noble completed the acquisition of Clayton Williams Energy, Inc. Upon closing of the acquisition, approximately 64,000 net acres in the Delaware Basin were dedicated to us for infield crude oil, natural gas, and produced water gathering. We have a ROFR on the remaining acreage acquired by Noble. Additionally, an infield natural gas gathering dedication was added to the existing crude oil and produced water gathering dedication on substantially all of Noble’s legacy 47,000 Delaware Basin net acres. Both acreage dedications are held by the Blanco River DevCo.
In conjunction with the new dedications, we waived our ROFR for natural gas processing on approximately 80,000 net acres in the Delaware Basin, of which, approximately 35,000 net acres were dedicated to a third party through 2021.

53


Development Project Updates
Laramie River DevCo LP During the second quarter of 2017, we commenced Fresh water deliveries to an unaffiliated third party in the Greeley Crescent IDP. We also began gathering crude oil and produced water for this customer in the third quarter of 2017. Additionally, we connected 90 equivalent wells, normalized to 4,500 lateral feet, to our system during 2017.
Blanco River DevCo LP We began construction of the Billy Miner I and the Jesse James CGFs. During the third quarter of 2017, we placed the Billy Miner I CGF in service. As a result of the strong well performance and plans for additional wells to be tied into the facility, we completed a debottlenecking project with minor facility modifications in late August, increasing crude oil, natural gas and produced water throughput capacity to 15 MBbl/d, 30 MMcf/d, and 30 MBw/d, respectively. During the fourth quarter of 2017, our second CGF, Jesse James, was placed in service. The Jesse James CGF currently has crude oil, natural gas and produced water throughput capacity of 15 MBbl/d, 30 MMcf/d, and 30 MBw/d, respectively. We connected 29 equivalent wells to our gathering systems during 2017. Additionally, we also completed backbone gathering infrastructure on the Southern portion of Noble Energy's Delaware Basin Acreage. Construction is underway on three additional CGFs which are scheduled to be online by the first half of 2018.
Trinity River DevCo LLC We completed construction of the 15-mile connection from our CGFs in the Delaware Basin to the Advantage pipeline. Crude oil from the Billy Miner I and Jesse James CGFs began flowing through the connection to the Advantage Pipeline.
Colorado River DevCo LP During 2017, we connected 189 equivalent wells, to our gathering systems in the Wells Ranch IDP and East Pony IDP. We also delivered fresh water to 110 equivalent wells in the Wells Ranch IDP. At the Wells Ranch CGF, we successfully completed a produced water expansion project, which increased produced water capacity to 30 MBbl/d.
Green River DevCo LP During 2017, we began construction activities on the expansion of our freshwater system in the Mustang IDP. The freshwater expansion commenced operations in December 2017. Additionally, construction is underway on the backbone gathering infrastructure buildout, which we expect to complete in early 2018.
San Juan River DevCo LP During 2017, we delivered freshwater to 88 equivalent wells in the East Pony IDP.

How We Evaluate Our Operations
Our management uses a variety of financial and operating metrics, each as described in more detail below, to analyze our performance. These metrics are significant factors in assessing our operating results and profitability and include:
throughput volumes (Gathering Systems and Fresh Water Delivery reportable segments);
operating costs and expenses;
Adjusted EBITDA (non-GAAP financial measure);
distributable cash flow (non-GAAP financial measure); and
capital expenditures.

54


RESULTS OF OPERATIONS
Results of operations were as follows:
 
Year Ended December 31,
(thousands)
2017
 
2016
 
2015
Revenues
 
 
 
 
 
Midstream Services — Affiliate
$
224,401

 
$
160,724

 
$
87,837

Midstream Services — Third Party
14,880

 

 

Total Revenues
239,281

 
160,724

 
87,837

Costs and Expenses
 
 
 
 
 
Direct Operating
54,007

 
29,107

 
16,933

Depreciation and Amortization
12,953

 
9,066

 
6,891

General and Administrative
13,396

 
9,914

 
2,771

Total Operating Expenses
80,356

 
48,087

 
26,595

Operating Income
158,925

 
112,637

 
61,242

Other (Income) Expense
 
 
 
 
 
Interest Expense, Net of Amount Capitalized
1,603

 
3,373

 
4,595

Investment Income
(6,334
)
 
(4,526
)
 
(4,621
)
Total Other (Income) Expense
(4,731
)
 
(1,153
)
 
(26
)
Income Before Income Taxes
163,656

 
113,790

 
61,268

Income Tax Provision
20

 
28,288

 
23,226

Net Income
163,636

 
85,502

 
$
38,042

Less: Net Income Prior to the IPO on September 20, 2016

 
45,990

 
N/A
Net Income Subsequent to the IPO on September 20, 2016
163,636

 
39,512

 
N/A
Less: Net Income Attributable to Noncontrolling Interests
23,064

 
11,054

 
N/A
Net Income Attributable to Noble Midstream Partners LP
$
140,572

 
$
28,458

 
N/A
 
 
 
 
 
 
Adjusted EBITDA(1) Attributable to Noble Midstream Partners LP
$
154,509

 
$
30,697

 
N/A
 
 
 
 
 
 
Distributable Cash Flow(1) of Noble Midstream Partners LP
$
137,935

 
$
28,425

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

Throughput Volumes
The amount of revenue we generate primarily depends on the volumes of crude oil, natural gas and water for which we provide midstream services. These volumes are affected primarily by the level of drilling and completion activity by our customers in our areas of operations, and by changes in the supply of and demand for crude oil, natural gas and NGLs in the markets served directly or indirectly by our assets.
Our customers’ willingness to engage in drilling and completion activity is determined by a number of factors, the most important of which are the prevailing and projected prices of crude oil and natural gas, the cost to drill and operate a well, expected well performance, the availability and cost of capital, and environmental and government regulations. We generally expect the level of drilling to positively correlate with long-term trends in commodity prices. Similarly, production levels nationally and regionally generally tend to positively correlate with drilling activity.
Our customers have dedicated acreage to us based on the services we provide. Our commercial agreements with Noble provide that, in addition to our existing dedicated acreage, any future acreage that is acquired by Noble in the IDP areas, and that is not subject to a pre-existing third-party commitment, will be included in the dedication to us for midstream services, including gathering and treating.

55


Revenues and throughput volumes related to certain midstream services of our Gathering Systems and Fresh Water Delivery reportable segments were as follows:
 
Year Ended December 31,
 
2017
 
2016
 
2015
Colorado River DevCo LP (1)
 
 
 
 
 
Crude Oil Gathering Volumes (Bbl/d)
56,531

 
45,236

 
33,977

Natural Gas Gathering Volumes (MMBtu/d)
172,284

 
132,147

 
86,103

Produced Water Gathering Volumes (Bbl/d)
14,097

 
10,592

 
5,198

Fresh Water Delivery Volumes (Bbl/d)
83,856

 
64,306

 
30,746

Gathering and Fresh Water Delivery Revenues  Affiliate (in thousands) (2)
$
175,258

 
$
132,161

 
$
72,641

 
 
 
 
 
 
San Juan River DevCo LP (1)
 
 
 
 
 
Fresh Water Delivery Volumes (Bbl/d)
34,676

 
22,423

 
21,234

Fresh Water Delivery Revenues Affiliate (in thousands) (2)
$
37,590

 
$
17,272

 
$
10,498

 
 
 
 
 
 
Green River DevCo LP (1)
 
 
 
 
 
Fresh Water Delivery Volumes (Bbl/d)

 
7,498

 

Fresh Water Delivery Revenues Affiliate (in thousands) (2)
$

 
$
4,728

 
$

 
 
 
 
 
 
Blanco River DevCo LP (1)
 
 
 
 
 
Crude Oil Gathering Volumes (Bbl/d)
3,791

 

 

Natural Gas Gathering Volumes (MMBtu/d)
8,634

 

 

Produced Water Gathering Volumes (Bbl/d)
7,996

 

 

Gathering Revenues  Affiliate (in thousands) (2)
$
5,876

 
$

 
$

 
 
 
 
 
 
Laramie River DevCo (1)
 
 
 
 
 
Crude Oil Gathering Volumes (Bbl/d)
5,333

 

 

Produced Water Gathering Volumes (Bbl/d)
2,338

 

 

Fresh Water Delivery Volumes (Bbl/d)
37,458

 

 

Gathering and Fresh Water Delivery Revenues  Third Party (in thousands) (2)
$
14,880

 
$

 
$

 
 
 
 
 
 
Total Gathering Systems
 
 
 
 
 
Crude Oil Gathering Volumes (Bbl/d)
65,655

 
45,236

 
33,977

Natural Gas Gathering Volumes (MMBtu/d)
180,918

 
132,147

 
86,103

Crude Oil and Natural Gas Gathering Volumes (MBoe/d)
89

 
62

 
45

Produced Water Gathering Volumes (Bbl/d)
24,431

 
10,592

 
5,198

Gathering Revenues (in thousands) (2)
$
146,835

 
$
94,160

 
$
56,042

 
 
 
 
 
 
Total Fresh Water Delivery
 
 
 
 
 
Fresh Water Services Volumes (Bbl/d)
155,990

 
94,227

 
51,980

Fresh Water Delivery Revenues (in thousands) (2)
$
86,769

 
$
60,001

 
$
27,097

(1) 
See Item 8. Financial Statements and Supplementary Data – Note 1. Organization and Nature of Operations for DevCo ownership interests.
(2) 
Effective January 1, 2015, we entered into multiple commercial agreements with Noble, for which we receive volumetric fees for the midstream services we provide.

56


Revenues
Revenues from our Gathering System and Fresh Water Delivery reportable segments were as follows:
 
 
 
Increase
from Prior Year
 
 
 
Increase
from Prior Year
 
 
(in thousands)
2017
 
 
2016
 
 
2015
Year Ended December 31,
 
 
 
 
 
 
 
 
 
Crude Oil, Natural Gas and Produced Water Gathering — Affiliate
$
142,864

 
52
 %
 
$
94,160

 
68
%
 
$
56,042

Crude Oil, Natural Gas and Produced Water Gathering — Third Party
3,971

 
N/M

 

 
N/M

 

Fresh Water Delivery Affiliate
75,860

 
26
 %
 
60,001

 
121
%
 
27,097

Fresh Water Delivery — Third Party
10,909

 
N/M

 

 
N/M

 

Crude Oil Treating Affiliate
4,473

 
(17
)%
 
5,371

 
22
%
 
4,403

Other Affiliate
1,204

 
1
 %
 
1,192

 
304
%
 
295

Total Midstream Services Revenues
$
239,281

 
49
 %
 
$
160,724

 
83
%
 
$
87,837

N/M amount is not meaningful.
Revenues Trend Analysis
We derive a substantial portion of our revenues from commercial agreements with Noble. Revenues from midstream services increased during 2017 as compared with 2016 due to the following:
an increase of $17.6 million in fresh water delivery revenues driven by increased fresh water volumes delivered to the Wells Ranch IDP and East Pony IDP due to fresh water volumes required per well for higher intensity completions;
an increase of $15.6 million in water logistic services revenues, including revenue derived from water transfer, hauling, recycling, and disposal services, driven by increased services in the Wells Ranch IDP and East Pony IDP;
an increase of $14.9 million in crude oil and produced water gathering services revenues and fresh water delivery revenues due to the commencement of services in the Greeley Crescent IDP to an unaffiliated third party during 2017;
an increase of $9.6 million in natural gas gathering services revenues driven by increased throughput volumes in our Wells Ranch IDP natural gas gathering systems resulting from expansion and gathering system growth;
an increase of $10.3 million in crude oil gathering services revenues driven by increased throughput volumes in our Wells Ranch IDP and East Pony IDP crude oil gathering systems resulting from expansion and gathering system growth;
an increase of $6.2 million in gathering revenues and fresh water delivery revenues driven by rate escalations;
an increase of $5.9 million in crude oil, natural gas, and produced water gathering services due to the commencement of services in the Delaware Basin during third quarter 2017;
partially offset by:
a decrease of $4.7 million in fresh water delivery revenues related to the Mustang IDP due to the timing of well completion activity by Noble.
Revenues from midstream services increased during 2016 as compared with 2015 due to the following:
an increase of $13.6 million in crude oil gathering revenues due to higher volumes flowing through the expanded Wells Ranch IDP and crude oil gathering system, driven by Noble’s 2016 well completion activities, as well as a rate increase;
an increase of $14.1 million in natural gas gathering revenues due to higher volumes flowing through the expanded Wells Ranch IDP and natural gas gathering system, driven by Noble’s 2016 well completion activities, as well as a rate increase;
an increase of $8.9 million in produced water gathering revenues due to higher volumes flowing through the expanded Wells Ranch IDP and water gathering system, driven by Noble’s 2016 well completion activities,
an increase of $32.9 million in fresh water delivery revenues due to higher fresh water volumes delivered to the Wells Ranch IDP as required for higher intensity well completions, the initiation of fresh water delivery services to the Mustang IDP as well as a rate increase;
an increase of $5.2 million related to water logistic services, including water transfer and disposal services, and electricity pass-through revenues driven by the commencement of both services during fourth quarter 2015;
partially offset by:
a decrease of $3.7 million in produced water gathering services due to a rate decrease at the Wells Ranch IDP area.

57


Costs and Expenses
Direct Operating Expense
We seek to maximize the profitability of our operations in part by minimizing, to the extent appropriate, expenses directly associated with operating our assets. Direct labor costs, ad valorem taxes, repair and maintenance costs, integrity management costs, utilities and contract services comprise the most significant portion of our operations and maintenance expense. Many of these expenses remain relatively stable across broad ranges of throughput volumes, but a portion of these expenses can fluctuate from period to period depending on the mix of activities performed during that period and the timing of these expenses. We also seek to manage operating expenditures on our midstream systems by scheduling maintenance over time to avoid significant variability in our maintenance expenditures and minimize their impact on our cash flow.
General and Administrative Expense
Following the completion of the IPO, Noble charges us a combination of direct and allocated charges for general and administrative services. Direct charges include a fixed fee under our omnibus agreement and compensation of our executives under our secondment agreement based on the percentage of time spent working on us. Between January 2015 and the IPO date, Noble charged us a fixed fee for overhead and support services.
We incur incremental general and administrative expenses attributable to being a publicly traded partnership, including expenses associated with: annual, quarterly and current reporting with the SEC; tax return and Schedule K-1 preparation and distribution; Sarbanes-Oxley Act of 2002 compliance; NYSE listing; independent auditor fees; legal fees; investor relations expenses; transfer agent and registrar fees; incremental salary and benefits costs of seconded employees; outside director fees; director and officer insurance coverage expenses; and compensation expense associated with the LTIP.
Costs and Expenses Trend Analysis
Costs and expenses were as follows:
 
 
 
Increase
from Prior Year
 
 
 
Increase
from Prior Year
 
 
(in thousands)
2017
 
 
2016
 
 
2015
Year Ended December 31,
 
 
 
 
 
 
 
 
 
Costs and Expenses
 
 
 
 
 
 
 
 
 
Direct Operating
$
54,007

 
86
%
 
$
29,107

 
72
%
 
$
16,933

Depreciation and Amortization
12,953

 
43
%
 
9,066

 
32
%
 
6,891

General and Administrative
13,396

 
35
%
 
9,914

 
258
%
 
2,771

Total Operating Expenses
$
80,356

 
67
%
 
$
48,087

 
81
%
 
$
26,595

Direct Operating Expenses Direct operating expenses increased during 2017 as compared with 2016 and increased during 2016 as compared with 2015. The increases in direct operating expenses by reportable segment were as follows:
Gathering Systems Gathering Systems direct operating expenses increased $22.7 million during 2017 as compared with 2016 and increased $0.6 million during 2016 as compared with 2015. The increase in both years was primarily attributable to an increase in gathering systems and facilities operating expense associated with higher gathered volumes, general repairs and maintenance of our gathering systems and facilities, and produced water services expense resulting from services provided by third parties. In 2016, the increase in Gathering Systems direct operating expenses was partially offset by a decrease in crude oil treating expense due to a reduction in quantities treated in our facilities.
Fresh Water Delivery Fresh Water Delivery direct operating expenses increased $1.6 million during 2017 as compared with 2016 primarily due to an increase in water delivery and services expense driven by an increase in fresh water volumes required per well for higher intensity completions. Fresh Water Delivery direct operating expenses increased $11.8 million during 2016 as compared with 2015 primarily due to an increase in water delivery and services expense driven by an increase in fresh water volumes required per well for higher intensity completions and an expanded scope of services delivered.
Investments and Other Investments and Other direct operating expenses increased $0.6 million during 2017 as compared with 2016 due to increased insurance expense. Investments and Other direct operating expenses decreased $0.3 million during 2016 as compared with 2015 primarily due to decreased insurance expense. Prior to the IPO, insurance expense was allocated from Noble to our Predecessor.

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Depreciation and Amortization Depreciation and amortization expense increased during 2017 as compared with 2016 and increased during 2016 as compared with 2015. The increases in direct operating expenses by reportable segment were as follows:
Gathering Systems Gathering Systems depreciation and amortization expense increased $3.3 million during 2017 as compared with 2016 primarily due to assets placed in service in 2017. Assets placed in service were associated with the expansion of the Wells Ranch CGF and gathering system, construction of the Greeley Crescent gathering system, construction of the Delaware Basin gathering system, and completion of the Jesse James and Billy Miner I CGFs. Gathering Systems depreciation and amortization expense increased $2.1 million during 2016 as compared with 2015 primarily due to assets placed in service as a result of the expansion of the Wells Ranch CGF and commissioning of the East Pony crude oil gathering system during 2016 and the expansion of the Wells Ranch gathering system at the end of third quarter 2015.
Fresh Water Delivery Fresh Water Delivery depreciation and amortization expense increased $0.6 million during 2017 as compared with 2016 primarily due to assets placed in service in 2017. Assets placed in service were associated with the construction of the Greeley Crescent fresh water delivery system and expansion of the Mustang fresh water delivery system. Fresh Water Delivery depreciation and amortization expense was flat for 2016 as compared with 2015.
General and Administrative Expense General and administrative expense is recorded within our Investments and Other reportable segment. General and administrative expense increased $3.5 million during 2017 as compared with 2016. The increase is primarily due to increased third party general and administrative expenses such as legal and financial advisory fees resulting from transactions. See Item 8. Financial Statements and Supplementary Data – Note 3. Transactions with Affiliates.
General and administrative expense increased $7.1 million during 2016 as compared with 2015. The increase is due to the omnibus agreement with Noble that we entered into effective as of the IPO date and that provides for payment of an annual general and administrative fee, initially in the amount of $6.9 million (prorated for the first year of service), for the provision of certain services by Noble and its affiliates. The increase is also due to incremental expenses that we now incur related to our being a publicly traded partnership.
Other (Income) Expense Trend Analysis
 
 
 
Increase (Decrease)
from Prior Year
 
 
 
Increase (Decrease)
from Prior Year
 
 
(in thousands)
2017
 
 
2016
 
 
2015
Year Ended December 31,
 
 
 
 
 
 
 
 
 
Other (Income) Expense
 
 
 
 
 
 
 
 
 
Interest Expense
$
4,059

 
(3
)%
 
$
4,180

 
(41
)%
 
$
7,114

Capitalized Interest
(2,456
)
 
204
 %
 
(807
)
 
(68
)%
 
(2,519
)
Interest Expense, Net
1,603

 
(52
)%
 
3,373

 
(27
)%
 
4,595

Investment Income
(6,334
)
 
40
 %
 
(4,526
)
 
(2
)%
 
(4,621
)
Total Other (Income) Expense
$
(4,731
)
 
310
 %
 
$
(1,153
)
 
4,335
 %
 
$
(26
)
Interest Expense, Net Interest Expense is recorded within our Investments and Other reportable segment. For periods prior to the IPO, interest expense represents allocations from Noble to our Predecessor. The allocations were based on the percentage that our Predecessor’s capital expenditures comprised of Noble’s total consolidated capital expenditures. For periods subsequent to the IPO, interest expense represents interest incurred in connection with our revolving credit facility. Our interest expense includes interest on outstanding balances 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 during the year. See Item 8. Financial Statements and Supplementary Data – Note 4. Property, Plant and Equipment for our construction-in-progress balances as of December 31, 2017 and 2016.
Interest expense decreased $0.1 million during 2017 as compared with 2016. The decrease is due primarily to increased interest expense allocations from Noble during the 2016 periods partially offset by interest incurred in connection with our revolving credit facility during the 2017 periods. Capitalized interest increased $1.6 million during 2017 as compared with 2016 due to an increase in construction-in-progress during 2017 as compared with 2016.
Interest expense decreased $2.9 million during 2016 as compared with 2015 as our Predecessor’s capital expenditures represented a lower percentage of Noble’s total consolidated capital expenditures during 2016 as compared with 2015 and the allocation of interest expense ceased subsequent to the IPO. Interest expense during 2016 also includes the non-cash amortization of origination fees and commitment fees on the undrawn portion of our revolving credit facility. No amounts were

59


drawn on our revolving credit facility during 2016. Capitalized interest decreased $1.7 million during 2016 as compared with 2015 due to a decrease in our average construction-in-progress during 2016 as compared with 2015 .
Investment Income
Investment income is recorded within our Investments and Other reportable segment. Investment income increased during 2017 as compared with 2016 primarily due to earnings from our investment in the Advantage Joint Venture. Crude oil throughput volumes during 2017 averaged 44 MBbl/d. Investment income was flat for 2016 as compared with 2015.
Income Tax Provision
See Item 8. Financial Statements and Supplementary Data – Note 13. 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 (used in) operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Adjusted EBITDA excludes some, but not all, items that affect net income or net cash, and these measures may vary from those of other companies. As a result, our Adjusted EBITDA may not be comparable to similar measures of other companies in our industry.
For a reconciliation of Adjusted EBITDA to its most comparable measures calculated and presented in accordance with GAAP, see Reconciliation of Non-GAAP Financial Measures, below.
We define Adjusted EBITDA as net income (loss) before income taxes, net interest expense, depreciation and amortization and unit-based compensation. Adjusted EBITDA is used as a supplemental financial measure by management and by external users of our financial statements, such as investors, industry analysts, lenders and ratings agencies, to assess:
our operating performance as compared with those of other companies in the midstream energy industry, without regard to financing methods, historical cost basis or capital structure;
the ability of our assets to generate sufficient cash flow to make distributions to our partners;
our ability to incur and service debt and fund capital expenditures; and
the viability of acquisitions and other capital expenditure projects and the returns on investment of various investment opportunities.
We believe that the presentation of Adjusted EBITDA provides information useful to investors in assessing our financial condition and results of operations. The GAAP measures most directly comparable to Adjusted EBITDA are net income and net cash provided by operating activities. Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income, net cash provided by operating activities or any other measure as reported in accordance with GAAP.
Distributable Cash Flow (Non-GAAP Financial Measure)
Distributable cash flow should not be considered an alternative to net income, net cash provided by operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Distributable cash flow excludes some, but not all, items that affect net income or net cash provided by operating activities, and these measures may vary from those of other companies. As a result, our distributable cash flow may not be comparable to similar measures of other companies in our industry.
For a a reconciliation of distributable cash flow to its most comparable measures calculated and presented in accordance with GAAP, see Reconciliation of Non-GAAP Financial Measures, below.
We define distributable cash flow as Adjusted EBITDA less estimated maintenance capital expenditures and cash interest paid. Distributable cash flow does not reflect changes in working capital balances. Our partnership agreement requires us to distribute all available cash on a quarterly basis, and distributable cash flow is one of the factors used by the board of directors of our General Partner to help determine the amount of cash that is available to our unitholders for a given period. Therefore, we believe distributable cash flow provides information useful to investors in assessing our financial condition and results of operations. The GAAP measures most directly comparable to distributable cash flow are net income and net cash provided by operating activities. Distributable cash flow should not be considered an alternative to, or more meaningful than, net income, net cash provided by operating activities or any other measure as reported in accordance with GAAP.

60


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

Reconciliation of Net Income to Adjusted EBITDA and Distributable Cash Flow
 
Year Ended December 31,
(thousands)
2017
 
2016
 
2015
Reconciliation from Net Income
 
 
 
 
 
Net Income
$
163,636

 
$
85,502

 
$
38,042

Add:
 
 
 
 
 
Depreciation and Amortization
12,953

 
9,066

 
6,891

Interest Expense, Net of Amount Capitalized
1,603

 
3,373

 
4,595

Income Tax Provision
20

 
28,288

 
23,226

Unit-Based Compensation
790

 
42

 

Adjusted EBITDA
179,002

 
126,271

 
$
72,754

Less: