UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C.  20549

FORM 10-Q

ý QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2018

OR

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from _____to_____

Commission file number: 001-37640

NOBLE MIDSTREAM PARTNERS LP

(Exact name of registrant as specified in its charter)

Delaware	47-3011449
(State or other jurisdiction of incorporation or organization)	(I.R.S. employer identification number)
1001 Noble Energy Way
Houston, Texas	77070
(Address of principal executive offices)	(Zip Code)
(281) 872-3100 (Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes ý No o

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).

Yes ý    No o

 Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller

reporting company, or an emerging growth company. See the definitions of “large accelerated filer”, “accelerated filer”, “smaller reporting company” and “emerging growth company ” in Rule 12b-2 of the Exchange Act.

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

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying

with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes o    No ý

As of October 29, 2018, the registrant had 23,761,725 Common Units and 15,902,584 Subordinated Units outstanding.

Table of Contents

Part I. Financial Information	3
Item 1. Financial Statements	3
Consolidated Balance Sheets	3
Consolidated Statements of Operations and Comprehensive Income	4
Consolidated Statements of Cash Flows	5
Consolidated Statement of Changes in Equity	6
Notes to Consolidated Financial Statements	7
Note 1. Organization and Nature of Operations	7
Note 2. Basis of Presentation	8
Note 3. Acquisition	12
Note 4. Transactions with Affiliates	14
Note 5. Property, Plant and Equipment	14
Note 6. Intangible Assets	14
Note 7. Long-Term Debt	15
Note 8. Asset Retirement Obligations	16
Note 9. Segment Information	16
Note 10. Partnership Distributions	18
Note 11. Net Income per Limited Partner Unit	18
Note 12. Commitments and Contingencies	19
Item 2.  Management’s Discussion and Analysis of Financial Condition and Results of Operations	20
Item 3.  Quantitative and Qualitative Disclosures About Market Risk	32
Item 4.  Controls and Procedures	34
Part II. Other Information	34
Item 1.  Legal Proceedings	34
Item 1A.  Risk Factors	34
Item 6.  Exhibits	35
Signatures	37

2

Part I. Financial Information

Item 1. Financial Statements

Noble Midstream Partners LP

Consolidated Balance Sheets

(in thousands, unaudited)

	September 30, 2018			December 31, 2017
ASSETS
Current Assets
Cash and Cash Equivalents	$	18,201		$	18,026
Restricted Cash	951			37,505
Accounts Receivable — Affiliate	32,130			27,539
Accounts Receivable — Third Party	25,564			2,641
Crude Oil Inventory	2,340			—
Other Current Assets	2,321			389
Total Current Assets	81,507			86,100
Property, Plant and Equipment
Total Property, Plant and Equipment, Gross	1,433,083			706,039
Less: Accumulated Depreciation and Amortization	(68,454		)	(44,271		)
Total Property, Plant and Equipment, Net	1,364,629			661,768
Intangible Assets, Net	318,344			—
Goodwill	110,882			—
Investments	81,208			80,461
Other Noncurrent Assets	2,892			1,429
Total Assets	$	1,959,462		$	829,758
LIABILITIES
Current Liabilities
Accounts Payable — Affiliate	$	2,414		$	1,616
Accounts Payable — Trade	109,962			109,893
Other Current Liabilities	7,885			2,876
Total Current Liabilities	120,261			114,385
Long-Term Liabilities
Long-Term Debt	548,968			85,000
Asset Retirement Obligations	15,770			10,416
Other Long-Term Liabilities	929			3,727
Total Liabilities	685,928			213,528
EQUITY
Partners’ Equity
Limited Partner
Common Units (23,758 and 23,712 units outstanding, respectively)	684,715			642,616
Subordinated Units (15,903 units outstanding)	(140,155		)	(168,136		)
General Partner	1,462			520
Total Partners’ Equity	546,022			475,000
Noncontrolling Interests	727,512			141,230
Total Equity	1,273,534			616,230
Total Liabilities and Equity	$	1,959,462		$	829,758

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

3

Noble Midstream Partners LP

Consolidated Statements of Operations and Comprehensive Income

(in thousands, except per unit amounts, unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
Revenues
Midstream Services — Affiliate	$	73,136		$	56,755		$	204,323		$	161,186
Midstream Services — Third Party	19,934			6,356			44,763			10,022
Crude Oil Sales — Third Party	46,093			—			109,781			—
Total Revenues	139,163			63,111			358,867			171,208
Costs and Expenses
Cost of Crude Oil Sales	44,379			—			105,830			—
Direct Operating	23,955			13,712			59,496			39,406
Depreciation and Amortization	18,376			3,562			46,076			8,483
General and Administrative	4,204			3,087			19,626			9,281
Total Operating Expenses	90,914			20,361			231,028			57,170
Operating Income	48,249			42,750			127,839			114,038
Other (Income) Expense
Interest Expense, Net of Amount Capitalized	3,506			594			6,220			961
Investment Income	(3,866		)	(1,633		)	(10,825		)	(4,339		)
Total Other Income	(360		)	(1,039		)	(4,605		)	(3,378		)
Income Before Income Taxes	48,609			43,789			132,444			117,416
State Income Tax Provision	(94		)	33			163			33
Net Income	48,703			43,756			132,281			117,383
Less: Net Income Attributable to Noncontrolling Interests	4,086			2,086			11,719			19,779
Net Income Attributable to Noble Midstream Partners LP	44,617			41,670			120,562			97,604
Less: Net Income Attributable to Incentive Distribution Rights	1,462			223			3,415			315
Net Income Attributable to Limited Partners	$	43,155		$	41,447		$	117,147		$	97,289
Net Income Attributable to Limited Partners Per Limited Partner Common and Subordinated Unit
Basic	$	1.09		$	1.15		$	2.96		$	2.93
Diluted	$	1.09		$	1.15		$	2.96		$	2.92
Weighted Average Limited Partner Units Outstanding — Basic
Common Units	23,688			19,990			23,686			17,354
Subordinated Units	15,903			15,903			15,903			15,903
Weighted Average Limited Partner Units Outstanding —Diluted
Common Units	23,704			20,005			23,701			17,365
Subordinated Units	15,903			15,903			15,903			15,903

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

4

Noble Midstream Partners LP

Consolidated Statements of Cash Flows

(in thousands, unaudited)

	Nine Months Ended September 30,
	2018			2017
Cash Flows From Operating Activities
Net Income	$	132,281		$	117,383
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities
Depreciation and Amortization	46,076			8,483
Income from Equity Method Investee, Net of Dividends	(4,049		)	(821		)
Unit-Based Compensation	1,057			581
Other Adjustments for Noncash Items Included in Income	523			288
Changes in Operating Assets and Liabilities, Net of Assets Acquired and Liabilities Assumed
Increase in Accounts Receivable	(14,054		)	(7,273		)
Increase in Accounts Payable	7,173			5,816
Other Operating Assets and Liabilities, Net	(1,071		)	(100		)
Net Cash Provided by Operating Activities	167,936			124,357
Cash Flows From Investing Activities
Additions to Property, Plant and Equipment	(540,991		)	(185,442		)
Black Diamond Acquisition, Net of Cash Acquired	(649,868		)	—
Additions to Investments	(426		)	(68,504		)
Distributions from Cost Method Investee	1,020			728
Net Cash Used in Investing Activities	(1,190,265		)	(253,218		)
Cash Flows From Financing Activities
Distributions to Noncontrolling Interests	(5,814		)	(19,849		)
Contributions from Noncontrolling Interests	593,034			52,806
Borrowings Under Revolving Credit Facility	690,000			245,000
Repayment of Revolving Credit Facility	(725,000		)	(45,000		)
Proceeds from Term Loan Credit Facility	500,000			—
Proceeds from Equity Offering, Net of Cash Offering Costs	—			138,084
Distribution to Noble for Contributed Assets	—			(245,000		)
Distributions to Unitholders	(63,220		)	(42,937		)
Debt Issuance Costs and Other	(3,050		)	(982		)
Net Cash Provided by Financing Activities	985,950			82,122
Decrease in Cash, Cash Equivalents, and Restricted Cash	(36,379		)	(46,739		)
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	55,531			57,421
Cash, Cash Equivalents, and Restricted Cash at End of Period	$	19,152		$	10,682

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

5

Noble Midstream Partners LP

Consolidated Statement of Changes in Equity

(in thousands, unaudited)

	Partnership
	Common Units			Subordinated Units			General Partner			Noncontrolling Interests			Total
December 31, 2016	$	308,338		$	(36,799	)	$	—		$	71,366		$	342,905
Net Income	51,117			46,172			315			19,779			117,383
Contributions from Noncontrolling Interests	—			—			—			51,503			51,503
Distributions to Noncontrolling Interests	—			—			—			(19,849		)	(19,849		)
Distributions to Unitholders	(22,333		)	(20,512		)	(92		)	—			(42,937		)
Net Proceeds from Private Placement	138,084			—			—			—			138,084
Distribution to Noble for the Contributed Assets	(28,459		)	(216,541		)	—			—			(245,000		)
Contributed Assets Transfer from Noble	6,371			48,473			—			(54,844		)	—
Unit-Based Compensation	581			—						—			581
September 30, 2017	$	453,699		$	(179,207	)	$	223		$	67,955		$	342,670
December 31, 2017	$	642,616		$	(168,136	)	$	520		$	141,230		$	616,230
Net Income	70,093			47,054			3,415			11,719			132,281
Contributions from Noncontrolling Interests	—			—			—			593,034			593,034
Distributions to Noncontrolling Interests	—			—			—			(5,814		)	(5,814		)
Distributions to Unitholders	(36,352		)	(24,395		)	(2,473		)	—			(63,220		)
Black Diamond Equity Ownership Promote Vesting (1)	7,335			5,322			—			(12,657		)	—
Unit-Based Compensation	1,057			—			—			—			1,057
Other	(34		)	—			—			—			(34		)
September 30, 2018	$	684,715		$	(140,155	)	$	1,462		$	727,512		$	1,273,534

⁽¹⁾  See Note 2. Basis of Presentation for further discussion of the Black Diamond equity ownership promote vesting.

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

6

Noble Midstream Partners LP

Notes to Consolidated Financial Statements (Unaudited)

Note 1. Organization and Nature of Operations

Organization Noble Midstream Partners LP (the Partnership, we, us or our) is a growth-oriented Delaware master limited partnership formed in December 2014 by our sponsor, Noble Energy, Inc. (Noble or Parent), to own, operate, develop and acquire a wide range of domestic midstream infrastructure assets. Our current focus areas are the Denver-Julesburg Basin (DJ Basin) in Colorado and the Southern Delaware Basin position of the Permian Basin (Delaware Basin) in Texas.

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

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

⁽¹⁾  The noncontrolling interest represents Noble’s retained ownership interest in each DevCo.

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

⁽³⁾  Our interest in the Advantage Joint Venture (defined below) is owned through Trinity River DevCo LLC.

Additionally, we own a 3.33% ownership interest (the White Cliffs Interest) in White Cliffs Pipeline L.L.C. as well as a 50% interest in Advantage Pipeline, L.L.C. (the Advantage Joint Venture).

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

• crude oil gathering systems;

• natural gas gathering systems and compression units;

• crude oil treating facilities;

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

• fresh water storage and delivery systems.

We generate revenues primarily by charging fees on a per unit basis for gathering crude oil and natural gas, delivering and storing fresh water, and collecting, cleaning and disposing of produced water. Additionally, we purchase and sell crude oil to customers at various delivery points on our gathering systems.

7

Noble Midstream Partners LP

Notes to Consolidated Financial Statements (Unaudited)

Note 2. Basis of Presentation

Basis of Presentation and Consolidation   The accompanying unaudited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States (U.S. GAAP) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and notes required by U.S. GAAP for complete financial statements. The accompanying consolidated financial statements at September 30, 2018 and December 31, 2017 and for the three and nine months ended September 30, 2018 and 2017 contain all normally recurring adjustments considered necessary for a fair presentation of our financial position, results of operations, cash flows and partners’ equity for such periods. Operating results for the three and nine months ended September 30, 2018 are not necessarily indicative of the results that may be expected for the year ending December 31, 2018. We have no items of other comprehensive income; therefore, our net income is identical to our comprehensive income.

Variable Interest Entities   Our consolidated financial statements include our accounts and the accounts of the DevCos, each of which we control as general partner. All intercompany balances and transactions have been eliminated upon consolidation. We have determined that the partners with equity at risk in each of the DevCos lack the authority, through voting rights or similar rights, to direct the activities that most significantly impact their economic performance; therefore, each DevCo is considered a variable interest entity, or VIE. Through our 100% ownership interest in Noble Midstream Services, LLC, a Delaware limited liability company which owns controlling interests in each of the DevCos, we have the authority to direct the activities that most significantly affect economic performance and the obligation to absorb losses or the right to receive benefits that could be potentially significant to us. Therefore, we are considered the primary beneficiary and consolidate each of the DevCos in our financial statements. A substantial portion of the financial statement activity associated with our DevCos is captured within the Gathering Systems and Fresh Water Delivery reportable segments. Although our investment in the Advantage Joint Venture is owned through Trinity River DevCo LLC, all financial statement activity associated with our investment is captured within the Investments and Other reportable segment. See Note 9. Segment Information.

On January 31, 2018, Black Diamond, an entity formed by Black Diamond Gathering Holdings LLC (the Noble Member), a wholly-owned subsidiary of Noble Midstream Partners LP, and Greenfield Midstream, LLC (the Greenfield Member), completed the acquisition of all of the issued and outstanding limited liability company interests in Saddle Butte Rockies Midstream, LLC and certain affiliates (collectively, Saddle Butte) from Saddle Butte Pipeline II, LLC (Seller). The acquisition of Saddle Butte will be referred to as the Black Diamond Acquisition. See Note 3. Acquisition. Our consolidated financial statements include the accounts of Black Diamond, which we control. We have determined that the partners with equity at risk in Black Diamond lack the authority, through voting rights or similar rights, to direct the activities that most significantly impact their economic performance. Therefore, Black Diamond is considered a VIE. Through our majority representation on the Black Diamond company board of directors as well as our responsibility as operator of the acquired system, we have the authority to direct the activities that most significantly affect economic performance and the obligation to absorb losses or the right to receive benefits that could be potentially significant to us. Therefore, we are considered the primary beneficiary and consolidate Black Diamond in our financial statements.

Accounting for Investments 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. We use the cost method of accounting for our White Cliffs Interest as we have virtually no influence over its operations and financial policies.

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

Black Diamond Equity Ownership Promote Vesting In accordance with the limited liability company agreement of Black Diamond, Noble Member received an equity ownership promote. The capital accounts for Noble Member and Greenfield Member at September 30, 2018 do not equal their agreed equity ownership interests due to the funding structure of the total Black Diamond Acquisition purchase price. See Note 3. Acquisition.

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

Use of Estimates   The preparation of consolidated financial statements in conformity with U.S. GAAP requires us to make a number of estimates and assumptions relating to the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ significantly from those estimates. Management evaluates estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment.

8

Noble Midstream Partners LP

Notes to Consolidated Financial Statements (Unaudited)

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

Goodwill As of September 30, 2018, our consolidated balance sheet includes goodwill of $110.9 million. This goodwill resulted from the Black Diamond Acquisition and represents the excess of the consideration paid over fair value of the net identifiable assets of the acquired business. All of our goodwill is assigned to the Black Diamond reporting unit within the Gathering Systems reportable segment. See Note 3. Acquisition and Note 9. Segment Information.

Goodwill is not amortized to earnings but is qualitatively assessed for impairment. We will assess goodwill for impairment annually during the third quarter, or more frequently as circumstances require, at the reporting unit level. If, based on our qualitative procedures, it is more likely than not that the fair value of the reporting unit is less than its carrying amount, we will perform the two-step goodwill impairment test. The two-step goodwill impairment test is also performed whenever events or changes in circumstances indicate that the carrying value may not be recoverable. See Recently Issued Accounting Standards – Intangibles – Goodwill and Other: Simplifying the Test for Goodwill Impairment, below, for newly issued accounting guidance regarding future goodwill impairment testing.

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

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

Our revolving credit facility and term loan credit facility are variable-rate, non-public debt. The fair value is estimated based on significant other observable inputs. As such, we consider the fair value of these facilities to be a Level 2 measurement on the fair value hierarchy. See Note 7. Long-Term Debt.

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

State Income Tax We are not a taxable entity for United States federal income tax purposes or for the majority of states that impose an income tax. As taxes are generally borne by our partners through the allocation of taxable income, we do not record deferred taxes related to the aggregate difference in the basis of our assets for financial and tax reporting purposes. During third quarter 2017, we commenced operations in the Delaware Basin and are subject to a Texas margin tax. The tax due is based on an entity’s apportioned taxable margin. We recorded a de minimis state income tax provision for the three and nine months ended September 30, 2018.

Supplemental Cash Flow Information We accrued $75.3 million and $72.5 million related to capital expenditures for projects in progress as of September 30, 2018 and September 30, 2017, respectively.

Concentration of Credit Risk For the nine months ended September 30, 2018, revenues from Noble and its affiliates comprised 82% and 57% of our midstream services revenues and total revenues, respectively. For the nine months ended September 30, 2018, revenues from a single third party customer comprised 61% and 19% of our crude oil sales revenues and total revenues, respectively. For the nine months ended September 30, 2017, revenues from Noble and its affiliates comprised 94% of total revenues.

Recently Adopted Accounting Standards

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

9

Noble Midstream Partners LP

Notes to Consolidated Financial Statements (Unaudited)

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

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

Recently Issued Accounting Standards

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

In the normal course of business, we enter into lease agreements and land easements to support our operations and may lease water-related, field-related and other assets. We will adopt the new standard on the effective date of January 1, 2019 using a modified retrospective approach as permitted under ASU 2018-11. We plan to make certain elections allowing us to not reassess contracts that commenced prior to adoption of the standard, not recognize right of use assets or lease liabilities associated with short-term leases, and account for existing land easements under current accounting policy.

We continue to execute a project plan, which includes contract review and assessment, data collection, and evaluation of our systems, processes and internal controls. In addition, we implemented a new lease accounting software which will facilitate in the adoption of this standard. Although we continue to assess the impact of the standard on our consolidated financial statements, we believe adoption and implementation will result in an increase to assets and liabilities as well as additional disclosures. We do not expect a material impact on our consolidated statement of operations.

Intangibles – Goodwill and Other: Simplifying the Test for Goodwill Impairment In January 2017, the FASB issued Accounting Standards Update No. 2017-04 (ASU 2017-04): Intangibles – Goodwill and Other – Simplifying the Test for Goodwill Impairment, to simplify how an entity is required to test goodwill for impairment by eliminating Step 2 from the goodwill impairment test. Step 2 measures a goodwill impairment loss by comparing the implied fair value of a reporting unit’s goodwill with the carrying amount of that goodwill. Under the new guidance, an entity will perform its annual, or interim, goodwill impairment test by comparing the fair value of a reporting unit with its carrying amount, with an impairment charge being recognized for the amount by which the carrying amount exceeds the reporting unit’s fair value. ASU 2017-04 will be effective for annual or any interim goodwill impairment tests in fiscal years beginning after December 15, 2019, with early adoption permitted. We are currently evaluating the provisions of ASU 2017-04 and have not yet determined if we will early adopt.

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

10

Noble Midstream Partners LP

Notes to Consolidated Financial Statements (Unaudited)

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

	Nine Months Ended September 30,
(in thousands)	2018		2017
Cash and Cash Equivalents at Beginning of Period	$	18,026	$	57,421
Restricted Cash at Beginning of Period (1)	37,505		—
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	$	55,531	$	57,421
Cash and Cash Equivalents at End of Period	$	18,201	$	10,682
Restricted Cash at End of Period (2)	951		—
Cash, Cash Equivalents, and Restricted Cash at End of Period	$	19,152	$	10,682

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

⁽²⁾  Restricted cash represents the amount held as collateral at September 30, 2018 for certain of our letters of credit.

Revenue Recognition We generate revenues by charging fees on a per unit basis for gathering crude oil and natural gas, delivering and storing fresh water, and collecting, cleaning and disposing of produced water. Also, we purchase and sell crude oil to customers at various delivery points on our gathering systems. We adopted ASC 606 on January 1, 2018, using the modified retrospective method. Under ASC 606, performance obligations are the unit of account and generally represent distinct goods or services that are promised to customers. The adoption of ASC 606 did not have an impact on the recognition, measurement and presentation of our revenues and expenses. See Note 9. Segment Information for disaggregation of revenue by reportable segment.

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

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

Transaction Price Allocated to Remaining Performance Obligations The majority of our revenue agreements have a term greater than one year, and as such we have utilized the practical expedient in ASC 606, which states that we are not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under our revenue agreements, each delivery generally represents a separate performance obligation; therefore, future volumes delivered are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.

The remainder of our revenue agreements, which relate to agreements with third parties, are short-term in nature with a term of one year or less. We have utilized an additional practical expedient in ASC 606 which exempts us from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of an agreement that has an original expected duration of one year or less.

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

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

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

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

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

11

Noble Midstream Partners LP

Notes to Consolidated Financial Statements (Unaudited)

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

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

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

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

Note 3. Acquisition

On January 31, 2018, Black Diamond completed the Black Diamond Acquisition for approximately $638.5 million in cash. Noble Member and Greenfield Member each funded its share of the purchase price, approximately $319.9 million and $318.6 million, respectively, through contributions to Black Diamond. Noble Member funded its share of the purchase price through a combination of cash on hand and borrowings under its revolving credit facility. See Note 7. Long-Term Debt.

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

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

In connection with the Black Diamond Acquisition, we have incurred acquisition and integration costs of $7.5 million during the nine months ended September 30, 2018. Our acquisition and integration costs include consulting, advisory, legal, transition services and other fees. All acquisition and integration costs were expensed and are included in general and administrative expense in our consolidated statements of operations.

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

Certain data necessary to complete the purchase price allocation is not yet available, and includes, but is not limited to, final appraisals of assets acquired and liabilities assumed. We expect to complete the purchase price allocation during the 12-month period following the acquisition date, during which time the value of the assets and liabilities, including any goodwill, may be revised as appropriate.

12

Noble Midstream Partners LP

Notes to Consolidated Financial Statements (Unaudited)

The following table sets forth our preliminary purchase price allocation:

(in thousands)
Cash Consideration	$	638,266
PDC Energy Payment	24,120
Current Liabilities Assumed	18,259
Total Purchase Price and Liabilities Assumed	$	680,645
Cash and Restricted Cash	$	12,518
Accounts Receivable	10,661
Other Current Assets	1,058
Property, Plant and Equipment	205,766
Intangible Assets  (1)	339,760
Fair Value of Identifiable Assets	569,763
Implied Goodwill (2)	110,882
Total Asset Value	$	680,645

⁽¹⁾  See Note 6. Intangible Assets.

⁽²⁾  Based upon the preliminary purchase price allocation, we have recognized $110.9 million of goodwill, all of which is assigned to the Black Diamond reporting unit within the Gathering Systems reportable segment. As a result of the acquisition, we expect to realize certain synergies which may result from our operation of the Black Diamond system.

The results of operations attributable to Black Diamond are included in our consolidated statements of operations beginning on February 1, 2018. Revenues of $133.6 million and pre-tax net loss of $11.6 million from Black Diamond were generated from February 1, 2018 to September 30, 2018 and revenues of $57.1 million and pre-tax net loss of $2.3 million from Black Diamond were generated during the three months ended September 30, 2018.

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

	Three Months Ended September 30,				Nine Months Ended September 30,
(in thousands, except per unit amounts)	2018		2017		2018		2017
Revenues	$	139,163	$	108,239	$	369,379	$	246,281
Net Income	48,703		41,158		129,796		96,638
Net Income Attributable to Noble Midstream Partners LP	$	44,617	$	39,316	$	118,896	$	83,497
Net Income Attributable to Limited Partners Per Limited Partner Common and Subordinated Unit
Basic	$	1.09	$	1.09	$	2.92	$	2.50
Diluted	$	1.09	$	1.09	$	2.92	$	2.50

13

Noble Midstream Partners LP

Notes to Consolidated Financial Statements (Unaudited)

Note 4. Transactions with Affiliates

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

	Three Months Ended September 30,				Nine Months Ended September 30,
(in thousands)	2018		2017		2018		2017
Crude Oil, Natural Gas and Produced Water Gathering	$	54,674	$	37,854	$	144,569	$	98,591
Fresh Water Delivery	17,416		17,589		56,774		58,256
Crude Oil Treating	980		1,037		2,914		3,473
Other	66		275		66		866
Total Revenues — Affiliate	$	73,136	$	56,755	$	204,323	$	161,186

Expenses General and administrative expense consists of the following:

	Three Months Ended September 30,				Nine Months Ended September 30,
(in thousands)	2018		2017		2018		2017
General and Administrative Expense — Affiliate	$	1,894	$	1,819	$	5,599	$	5,527
General and Administrative Expense — Third Party	2,310		1,268		14,027		3,754
Total General and Administrative Expense	$	4,204	$	3,087	$	19,626	$	9,281

Note 5. Property, Plant and Equipment

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

(in thousands)	September 30, 2018			December 31, 2017
Crude Oil, Natural Gas and Produced Water Gathering Systems and Facilities	$	1,178,292		$	451,275
Fresh Water Delivery Systems	78,613			76,745
Crude Oil Treating Facilities	20,099			20,099
Construction-in-Progress (1)	156,079			157,920
Total Property, Plant and Equipment, at Cost	1,433,083			706,039
Accumulated Depreciation and Amortization	(68,454		)	(44,271		)
Property, Plant and Equipment, Net	$	1,364,629		$	661,768

⁽¹⁾  Construction-in-progress at September 30, 2018 includes $108.4 million in gathering system projects, $17.4 million in fresh water delivery system projects and $30.3 million in equipment for use in future projects. Construction-in-progress at December 31, 2017 includes $157.4 million in gathering system projects and $0.5 million in fresh water delivery system projects.

Note 6. Intangible Assets

Our intangible assets as of September 30, 2018 are comprised of customer contracts and relationships from the Black Diamond Acquisition and were recorded under the acquisition method of accounting at their estimated fair values at the date of acquisition. The customer contracts we acquired are long-term, fixed-fee contracts for the purchase and sale of crude oil. See Note 2. Basis of Presentation for further discussion of our crude oil purchase and sale revenue agreements. Fair value was calculated using the multi-period excess earnings method under the income approach for the existing customers. This valuation method is based on first forecasting gross profit for the existing customers and then applying expected attrition rates. The operating cash flows were calculated by determining the costs required to generate gross profit from the existing customers. The key assumptions include overall gross profit growth, attrition rate of existing customers over time and the discount rate. 

We utilize the straight-line method of amortization for intangible assets with finite lives. The amortization period is reflective of the benefit pattern in which the estimated economic benefit is expected to be received over the estimated useful life of the

14

Noble Midstream Partners LP

Notes to Consolidated Financial Statements (Unaudited)

intangible asset. The estimated economic benefit was determined by assessing the life of the assets related to the contracts and relationships, likelihood of renewals, competitive factors, regulatory or legal provisions and maintenance costs.

Our intangible assets are as follows:

		September 30, 2018
	Useful Life	Intangible Assets, Gross (in thousands)		Accumulated Amortization (in thousands)		Intangible Assets, Net (in thousands)
Customer Contracts and Relationships	7-13 years (1)	$	339,760	$	21,416	$	318,344

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

Estimated future amortization expense related to the intangible assets at September 30, 2018 is as follows:

(in thousands)
Remainder of 2018	$	8,142
2019	32,301
2020	32,390
2021	32,301
2022	32,301
Thereafter	180,909
Total	$	318,344

Note 7. Long-Term Debt

Long-term debt as of September 30, 2018 and December 31, 2017 was as follows:

	September 30, 2018					December 31, 2017
(in thousands, except percentages)	Debt			Interest Rate		Debt		Interest Rate
Revolving Credit Facility, due March 9, 2023	$	50,000		3.32	%	$	85,000	2.75	%
Term Loan Credit Facility, due July 31, 2021	500,000			3.17	%	—		—	%
Long-Term Debt, Gross	550,000					85,000
Term Loan Credit Facility Unamortized Debt Issuance Costs	(1,032		)			—
Long-Term Debt	$	548,968				$	85,000

Revolving Credit Facility We maintain a revolving credit facility to fund working capital and to finance acquisitions and expansion capital expenditures. On January 31, 2018, in connection with the closing of the Black Diamond Acquisition, we entered into an amendment to increase the capacity on our revolving credit facility from $350 million to $530 million. On March 9, 2018, we entered into an additional amendment to extend the maturity of the facility to March 9, 2023 and increase the borrowing capacity to $800 million. In connection with our revolving credit facility amendments, we incurred $2.0 million of fees and expenses. The borrowing capacity on our revolving credit facility may be increased by up to an additional $350 million subject to certain conditions including compliance with the covenants contained in the credit agreement and requisite commitments from existing or new lenders. During third quarter 2018, we repaid $480 million on our revolving credit facility through the issuance of our term loan credit facility. See Term Loan Credit Facility below.

Borrowings under the revolving credit facility bear interest at a rate equal to an applicable margin plus, at our option, either (a) in the case of base rate borrowings, a rate equal to the highest of (1) the prime rate, (2) the greater of the federal funds rate or the overnight bank funding rate, plus 0.5% and (3) the LIBOR for an interest period of one month plus 1.00%; or (b) in the case of LIBOR borrowings, the offered rate per annum for deposits of dollars for the applicable interest period.

The unused portion of the revolving credit facility is subject to a commitment fee. Commitment fees began to accrue beginning on the date we entered into the revolving credit facility. As of December 31, 2017 and September 30, 2018, the commitment fee rate was 0.2%. Our revolving credit facility unamortized debt issuance costs totaled $1.4 million and $2.9 million as of December 31, 2017 and September 30, 2018, respectively, and are recorded within other noncurrent assets in our consolidated balance sheets.

15

Noble Midstream Partners LP

Notes to Consolidated Financial Statements (Unaudited)

The revolving credit facility requires us to comply with certain financial covenants as of the end of each fiscal quarter. We were in compliance with such covenants as of September 30, 2018.

Certain lenders that are a party to the credit agreement have in the past performed, and may in the future from time to time perform, investment banking, financial advisory, lending or commercial banking services for us for which they have received, and may in the future receive, customary compensation and reimbursement of expenses.

Term Loan Credit Facility On July 31, 2018, we entered into a three year senior unsecured term loan credit facility that permits aggregate borrowings of up to $500 million. Proceeds from the term loan credit facility were primarily used to repay a portion of the outstanding borrowings under our revolving credit facility and pay fees and expenses in connection with the term loan credit facility transactions. In connection with the term loan credit facility, we incurred $1.1 million of fees and expenses.

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

The term loan credit facility contains customary representations and warranties, affirmative and negative covenants, and events of default that are substantially the same as those contained in our revolving credit facility. Upon the occurrence and during the continuation of an event of default under the term loan credit facility, the lenders may declare all amounts outstanding under the term loan credit facility to be immediately due and payable and exercise other remedies as provided by applicable law.

Note 8. Asset Retirement Obligations

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

(in thousands)	Nine Months Ended September 30, 2018
Asset Retirement Obligations, Beginning Balance	$	10,416
Liabilities Incurred	4,878
Accretion Expense (1)	476
Asset Retirement Obligations, Ending Balance	$	15,770

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

Liabilities incurred were primarily related to the completion of Central Gathering Facilities (CGFs) in the Delaware Basin. During 2018, we completed the Coronado, Collier and Billy Miner Train II CGFs.

With respect to property, plant and equipment acquired in the Black Diamond Acquisition, it is our practice and current intent to maintain these assets and continue to make improvements as warranted. As a result, we believe that these assets have indeterminate lives for purposes of estimating asset retirement obligations because dates or ranges of dates upon which we would retire these assets cannot reasonably be estimated at this time; therefore, no asset retirement obligations have been recorded for these assets as of September 30, 2018.

Note 9. Segment Information

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

16

Noble Midstream Partners LP

Notes to Consolidated Financial Statements (Unaudited)

Summarized financial information concerning our reportable segments is as follows:

(in thousands)	Gathering Systems (1) (2)		Fresh Water Delivery (1)		Investments and Other (1) (3)			Consolidated
Three Months Ended September 30, 2018
Midstream Services — Affiliate	$	55,720	$	17,416	$	—		$	73,136
Midstream Services — Third Party	14,005		5,929		—			19,934
Crude Oil Sales — Third Party	46,093		—		—			46,093
Total Revenues	115,818		23,345		—			139,163
Income (Loss) Before Income Taxes	34,780		18,129		(4,300		)	48,609
Three Months Ended September 30, 2017
Midstream Services — Affiliate	$	39,166	$	17,589	$	—		$	56,755
Midstream Services — Third Party	1,574		4,782		—			6,356
Total Revenues	40,740		22,371		—			63,111
Income (Loss) Before Income Taxes	28,307		17,823		(2,341		)	43,789
Nine Months Ended September 30, 2018
Midstream Services — Affiliate	$	147,549	$	56,774	$	—		$	204,323
Midstream Services — Third Party	31,831		12,932		—			44,763
Crude Oil Sales — Third Party	109,781		—		—			109,781
Total Revenues	289,161		69,706		—			358,867
Income (Loss) Before Income Taxes	94,674		54,066		(16,296		)	132,444
Nine Months Ended September 30, 2017
Midstream Services — Affiliate	$	102,930	$	58,256	$	—		$	161,186
Midstream Services — Third Party	1,574		8,448		—			10,022
Total Revenues	104,504		66,704		—			171,208
Income (Loss) Before Income Taxes	70,633		53,298		(6,515		)	117,416
September 30, 2018
Total Assets	$	1,711,828	$	85,030	$	162,604		$	1,959,462
December 31, 2017
Total Assets	$	593,590	$	68,178	$	167,990		$	829,758

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

⁽²⁾  Our goodwill and intangible assets resulted from the Black Diamond Acquisition and are included in the Gathering Systems reportable segment. See Note 3. Acquisition and Note 6. Intangible Assets.

⁽³⁾  The Investments and Other segment includes our investments in the Advantage Joint Venture and White Cliffs Interest, all general Partnership activity not attributable to our DevCos.

17

Noble Midstream Partners LP

Notes to Consolidated Financial Statements (Unaudited)

Note 10. Partnership Distributions

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

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

⁽¹⁾  Distributions to common unitholders does not include distribution equivalent rights on units that vested under the Noble Midstream Partners LP 2016 Long-Term Incentive Plan (the LTIP).

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

Incentive Distribution Rights Noble currently holds Incentive Distribution Rights (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.

Cash Distributions On October 25, 2018, the board of directors of Noble Midstream GP LLC (our general partner) declared a quarterly cash distribution of $0.5597 per unit. The distribution will be paid on November 13, 2018, to unitholders of record as of November 5, 2018. Also on November 13, 2018, a cash incentive distribution of $1.5 million will be made to Noble related to its IDRs, based upon the level of distribution paid per Common and Subordinated Unit.

Note 11. Net Income Per Limited Partner Unit

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

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

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

18

Noble Midstream Partners LP

Notes to Consolidated Financial Statements (Unaudited)

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

	Three Months Ended September 30,				Nine Months Ended September 30,
(in thousands, except per unit amounts)	2018		2017		2018		2017
Net Income Attributable to Noble Midstream Partners LP	$	44,617	$	41,670	$	120,562	$	97,604
Less: Net Income Attributable to Incentive Distribution Rights	1,462		223		3,415		315
Net Income Attributable to Limited Partners	$	43,155	$	41,447	$	117,147	$	97,289
Net Income Attributable to Common Units	$	25,825	$	23,084	$	70,093	$	51,117
Net Income Attributable to Subordinated Units	17,330		18,363		47,054		46,172
Net Income Attributable to Limited Partners	$	43,155	$	41,447	$	117,147	$	97,289
Net Income Attributable to Limited Partners Per Limited Partner Common and Subordinated Unit
Basic	$	1.09	$	1.15	$	2.96	$	2.93
Diluted	$	1.09	$	1.15	$	2.96	$	2.92
Weighted Average Limited Partner Units Outstanding — Basic
Common Units	23,688		19,990		23,686		17,354
Subordinated Units	15,903		15,903		15,903		15,903
Weighted Average Limited Partner Units Outstanding — Diluted
Common Units	23,704		20,005		23,701		17,365
Subordinated Units	15,903		15,903		15,903		15,903
Antidilutive Restricted Units	21		4		22		6

Note 12. Commitments and Contingencies

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

19

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

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

• Executive Overview;

• Operating Outlook;

• Results of Operations; and

• Liquidity and Capital Resources.

MD&A is our analysis of the Partnership’s financial performance and of significant trends that may affect future performance. It should be read in conjunction with the consolidated financial statements and notes appearing elsewhere in this report and in our Annual Report on Form 10-K for the year ended December 31, 2017. It contains forward-looking statements including, without limitation, statements relating to our 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” and similar expressions identify forward-looking statements. We do 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 our disclosures in Item 3 of this report under the heading: “Disclosure Regarding Forward-Looking Statements.”

EXECUTIVE OVERVIEW

Overview

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

We are Noble’s primary vehicle for its midstream operations in the onshore United States (U.S.). 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 and financial results for third quarter 2018.

Significant Operating Highlights Include:

• average crude oil gathering volumes of 176,227 Bbl/d, an increase of 149% as compared with third quarter 2017;

• average natural gas gathering volumes of 323,082 MMBtu/d, an increase of 70% as compared with third quarter 2017;

• average produced water gathered volumes of 122,211 Bbl/d, an increase of 355% as compared with third quarter 2017;

• average fresh water delivered volumes of 195,395 Bbl/d, an increase of 12% as compared with third quarter 2017; and

• the commencement of gathering services on an initial well for a third party Delaware Basin producer.

Significant Financial Highlights Include:

• net income of $48.7 million, an increase of 11% as compared with third quarter 2017;

• net income attributable to the Partnership of $44.6 million, an increase of 7% as compared with third quarter 2017;

• net cash provided by operating activities of $167.9 million, an increase of 26% as compared with third quarter 2017;

• declared a distribution of $0.5597 per unit, an increase of 20% above the third quarter 2017 distribution per unit;

• Adjusted EBITDA (non-GAAP financial measure) of $71.1 million, an increase of 48% as compared with third quarter 2017;

• Adjusted EBITDA (non-GAAP financial measure) attributable to the Partnership of $59.4 million an increase of 29% as compared with third quarter 2017; and

• distributable cash flow (non-GAAP financial measure) of $49.2 million, an increase of 21% as compared with third quarter 2017.

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

20

OPERATING OUTLOOK

2018 Capital Investment Program

Our final 2018 capital investment program, excluding acquisitions, will accommodate a gross investment level of approximately $538 million to $550 million, with an investment level attributable to the Partnership of approximately $270 million to $275 million. During 2018, we revised our capital investment program to reflect new customer additions in the DJ and Delaware Basins as well as higher spending on infrastructure for Noble within the Delaware Basin and Mustang IDP area, partially offset by lower capital expenditures within the Greeley Crescent IDP area. We will continue to 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, cash generated from operations, borrowings under our revolving credit facility and, if necessary, the issuance of additional equity or debt securities.

Colorado Proposition #112

In the state of Colorado, initiatives have been underway to regulate, limit or ban hydraulic fracturing or other facets of crude oil and natural gas exploration, development or operations. On November 6, 2018, Colorado voters will be deciding whether or not to adopt Proposition #112, which, if passed, could significantly limit, or even prevent, the future development of crude oil and natural gas in areas where we perform midstream services. Such limitations or prohibitions could have a material adverse effect on our cash flows, results of operations, financial condition, and liquidity and could result in a material impairment of these assets. We continue to monitor proposed and new regulations and legislation in our operating jurisdictions to assess the potential impact on the Partnership. See Part II. Other Information - Item 1A. Risk Factors.

Regulatory Update

During 2018, the U.S. Administration imposed import tariffs of 25% on steel products and 10% on aluminum products, as well as quantitative restrictions on imports of steel and/or aluminum products from Argentina, Brazil, and South Korea (Australia has been exempted from the imposition of tariffs and implementation of quotas).  Key U.S. trading partners have threatened to retaliate, or already have retaliated, against imports of U.S.-origin goods and have initiated litigation at the World Trade Organization. The U.S. oil and gas industry relies on steel for drilling and completion of new wells as well as constructing pipelines and gathering facilities. Much of the steel required is in the form of specialty steel products, manufactured to exact specifications, and may not be available domestically in sufficient quantities.

Implementation of these tariffs will likely increase prices for specialty and other products used in various aspects of upstream, midstream and downstream activities. Furthermore, the tariffs and quantitative restrictions may cause disruption in the energy industry’s supply chain, resulting in delay or cessation of drilling efforts, postponement or cancellation of new inter-state or intra-state pipeline projects, which the industry relies on to transport its increasing U.S. onshore oil and gas production to market.

In addition, countries subject to the tariffs have threatened to retaliate with tariffs on U.S. products, potentially resulting in escalating trade disputes between the U.S. and certain of its trade partners. Trade and/or tariff disputes could result in increased costs or shortages of materials and supplies the industry relies on to produce, process and transport its oil and gas production. Moreover, trade and/or tariff disputes, could have negative impacts on the U.S. and global economies overall and result in less demand for our services.

Revenue Agreement Amendments with Noble

On August 2, 2018, Green River DevCo LP and Noble entered into amendments (the Amendments) to the following revenue agreements related to midstream services in the Mustang IDP:

• Second Amended and Restated Gas Gathering Agreement, Agreement Addendum 03, effective as of March 31, 2016, among Noble and Green River DevCo LP, as amended (the Gas Gathering Agreement);

• Second Amended and Restated Fresh Water Services Agreement, Agreement Addendum 03, effective as of March 31, 2016, among Noble and Green River DevCo LP, as amended (the Fresh Water Services Amendment);

• Second Amended and Restated Crude Oil Gathering Agreement, Agreement Addendum 03, effective as of March 31, 2016, among Noble and Green River DevCo LP, as amended (the Crude Oil Gathering Agreement); and

21

• Second Amended and Restated Produced Water Services Agreement, Agreement Addendum 03, effective as of March 31, 2016, among Noble and Green River DevCo LP, as amended (the Produced Water Services Agreement).

The Amendments to the Crude Oil Gathering and Produced Water Services Agreements established fees for services in the Mustang IDP which had not previously been provided for in the agreements. The Amendment to the Gas Gathering Agreement provides for a revised fee to reflect a spec gathering system rather than a central gathering facility as originally contemplated. The Amendment to the Fresh Water Services Agreement also provides for a revised fee to reflect higher per-well water usage associated with enhanced completions. Each of the Amendments are effective as of July 1, 2018.

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

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

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

• the assignment of its option to acquire up to 15 percent ownership in the EPIC NGL pipeline, which will expire in February 2019.

As discussed above, Colorado River DevCo LP and Noble entered into an amendment to the Second Amended and Restated Fresh Water Services Agreement (the Wells Ranch Fresh Water Services Amendment) which established the Wells Ranch MVC. The Wells Ranch Fresh Water Services Amendment establishes that the Wells Ranch MVC shall not apply in any year that Colorado Proposition #112 becomes effective (and if it is effective for a portion of the year, it shall be pro rated for such portion). See Part II. Other Information - Item 1A. Risk Factors.

Dedication and Commercial Update

We secured additional long-term dedications for Black Diamond, representing more than 200 wells across approximately 17,000 incremental acres. The additional dedications come from an existing third party customer on the system as well as a new third-party customer and increase total acreage dedicated to the system by 12% to approximately 158,000 acres. Activity on the acreage is expected to commence in late 2018.

On October 2, 2018, we entered into a letter of intent with Salt Creek Midstream LLC (Salt Creek) to form a 50/50 joint venture on the construction of a 200 thousand barrel of oil per day pipeline system in the Delaware Basin. The 95-mile, 20-inch diameter pipeline system will originate in Pecos County, Texas, with additional connections in Reeves County and Winkler County, Texas. The project footprint will be served by a combination of in-field crude oil gathering lines and a trunkline to a hub in Wink, Texas.

Salt Creek has commenced construction of the pipeline, with an expected operational date in the second quarter of 2019. We anticipate the execution of definitive agreements and closing of the transaction to occur in the fourth quarter of 2018. At closing, the project will be underpinned by approximately 180,000 dedicated gross acres and nearly 100 miles of pipeline in Pecos, Reeves, Ward and Winkler Counties, Texas, including an in-basin crude oil dedication of approximately 70,000 gross acres by Noble. Our five-year net capital investment is anticipated to total approximately $60 million to $80 million. 

Third Quarter 2018 Development Project Updates

Blanco River DevCo LP We connected 19 wells to our gathering systems during the quarter and commenced gathering services on an initial well for a third party Delaware Basin producer in September 2018. The third party customer development plan spans across approximately 13,000 dedicated acres in Reeves County, Texas, with additional activity on the acreage anticipated in 2019.

Green River DevCo LP We commenced the first full quarter of gathering services in the Mustang IDP area. We connected 25 wells to the Mustang gathering system and delivered fresh water to approximately two completion crews.

Trinity River DevCo LLC We reached a long-term agreement for the Advantage pipeline system to service a major producing company’s facilities on such customer’s Southern Delaware Basin position totaling approximately 20,000 net acres. First flow is expected to commence in October 2018.

22

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;

• operating costs and expenses;

• Adjusted EBITDA (non-GAAP financial measure);

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

• capital expenditures.

RESULTS OF OPERATIONS

Results of operations were as follows:

	Three Months Ended September 30,						Nine Months Ended September 30,
(thousands)	2018			2017			2018			2017
Revenues
Midstream Services — Affiliate	$	73,136		$	56,755		$	204,323		$	161,186
Midstream Services — Third Party	19,934			6,356			44,763			10,022
Crude Oil Sales — Third Party	46,093			—			109,781			—
Total Revenues	139,163			63,111			358,867			171,208
Costs and Expenses
Cost of Crude Oil Sales	44,379			—			105,830			—
Direct Operating	23,955			13,712			59,496			39,406
Depreciation and Amortization	18,376			3,562			46,076			8,483
General and Administrative	4,204			3,087			19,626			9,281
Total Operating Expenses	90,914			20,361			231,028			57,170
Operating Income	48,249			42,750			127,839			114,038
Other (Income) Expense
Interest Expense, Net of Amount Capitalized	3,506			594			6,220			961
Investment Income	(3,866		)	(1,633		)	(10,825		)	(4,339		)
Total Other Income	(360		)	(1,039		)	(4,605		)	(3,378		)
Income Before Income Taxes	48,609			43,789			132,444			117,416
State Income Tax Provision	(94		)	33			163			33
Net Income	48,703			43,756			132,281			117,383
Less: Net Income Attributable to Noncontrolling Interests	4,086			2,086			11,719			19,779
Net Income Attributable to Noble Midstream Partners LP	$	44,617		$	41,670		$	120,562		$	97,604
Adjusted EBITDA(1) Attributable to Noble Midstream Partners LP	$	59,351		$	46,005		$	162,287		$	106,386
Distributable Cash Flow(1) of Noble Midstream Partners LP	$	49,217		$	40,702		$	136,404		$	95,263

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

Throughput and Crude Oil Sales Volumes

The amount of revenue we generate primarily depends on the volumes of crude oil, natural gas and water for which we provide midstream services as well as the crude oil volumes we sell to customers. These volumes are affected primarily by the level of drilling and completion activity by our customers in our areas of operations, and by changes in the supply of and demand for crude oil, natural gas and NGLs in the markets served directly or indirectly by our assets.

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

23

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

	Three Months Ended September 30,		Nine Months Ended September 30,
	2018	2017	2018	2017
Colorado River DevCo LP (Wells Ranch IDP and East Pony IDP) (1)
Crude Oil Gathering Volumes (Bbl/d)	59,145	61,736	63,630	53,308
Natural Gas Gathering Volumes (MMBtu/d)	223,354	182,054	216,191	162,364
Produced Water Gathering Volumes (Bbl/d)	15,007	14,424	17,348	12,048
Fresh Water Delivery Volumes (Bbl/d)	72,216	80,395	58,295	89,372
San Juan River DevCo LP (East Pony IDP) (1)
Fresh Water Delivery Volumes (Bbl/d)	—	29,280	—	34,902
Green River DevCo LP (Mustang IDP) (1)
Crude Oil Gathering Volumes (Bbl/d)	5,657	—	1,942	—
Natural Gas Gathering Volumes (MMBtu/d)	9,062	—	3,111	—
Produced Water Gathering Volumes (Bbl/d)	8,123	—	2,816	—
Fresh Water Delivery Volumes (Bbl/d)	49,672	—	61,450	—
Blanco River DevCo LP (Delaware Basin) (1)
Crude Oil Gathering Volumes (Bbl/d)	33,689	3,791	23,272	1,277
Natural Gas Gathering Volumes (MMBtu/d)	89,439	7,926	59,477	2,671
Produced Water Gathering Volumes (Bbl/d)	90,162	7,670	58,845	2,585
Laramie River DevCo LP (Greeley Crescent IDP) (1)
Crude Oil Sales Volumes (Bbl/d)	7,266	—	6,164	—
Crude Oil Gathering Volumes (Bbl/d)	77,736	5,353	73,766	1,804
Natural Gas Gathering Volumes (MMBtu/d)	1,227	—	1,319	—
Produced Water Gathering Volumes (Bbl/d)	8,919	4,764	6,468	1,605
Fresh Water Delivery Volumes (Bbl/d)	73,507	65,085	54,694	38,709
Trinity River DevCo LLC (Delaware Basin) (1)
Natural Gas Compression Volumes (Mcf/d)	60,395	—	37,347	—
Total Gathering Systems
Crude Oil Sales Volumes (Bbl/d)	7,266	—	6,164	—
Crude Oil Gathering Volumes (Bbl/d)	176,227	70,880	162,610	56,389
Natural Gas Gathering Volumes (MMBtu/d)	323,082	189,980	280,098	165,035
Barrels of Oil Equivalent (Boe/d)	224,914	95,236	204,684	77,547
Produced Water Gathering Volumes (Bbl/d)	122,211	26,858	85,477	16,238
Natural Gas Compression Volumes (Mcf/d)	60,395	—	37,347	—
Total Fresh Water Delivery
Fresh Water Delivery Volumes (Bbl/d)	195,395	174,760	174,439	162,983

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

24

Revenues

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

(in thousands)	2018		2017		Increase (Decrease) From Prior Year
Three Months Ended September 30,
Crude Oil, Natural Gas and Produced Water Gathering — Affiliate	$	54,674	$	37,854	44	%
Crude Oil, Natural Gas and Produced Water Gathering — Third Party	12,459		1,574		N/M
Fresh Water Delivery — Affiliate	17,416		17,589		(1	)%
Fresh Water Delivery — Third Party	5,929		4,782		24	%
Crude Oil Treating — Affiliate	980		1,037		(5	)%
Crude Oil Sales — Third Party	46,093		—		N/M
Other — Affiliate	66		275		N/M
Other — Third Party	1,546		—		N/M
Total Revenues	$	139,163	$	63,111	121	%
Nine Months Ended September 30,
Crude Oil, Natural Gas and Produced Water Gathering — Affiliate	$	144,569	$	98,591	47	%
Crude Oil, Natural Gas and Produced Water Gathering — Third Party	28,796		1,574		N/M
Fresh Water Delivery — Affiliate	56,774		58,256		(3	)%
Fresh Water Delivery — Third Party	12,932		8,448		53	%
Crude Oil Treating — Affiliate	2,914		3,473		(16	)%
Crude Oil Sales — Third Party	109,781		—		N/M
Other — Affiliate	66		866		N/M
Other — Third Party	3,035		—		N/M
Total Revenues	$	358,867	$	171,208	110	%

N/M Amount is not meaningful

Revenues Trend Analysis

Revenues increased during third quarter 2018 as compared with third quarter 2017 and during the first nine months of 2018 as compared with the first nine months of 2017. The increases in revenues by reportable segment were as follows:

Gathering Systems Gathering Systems revenues increased during third quarter 2018 as compared with third quarter 2017 and during the first nine months of 2018 as compared with the first nine months of 2017. The increases were primarily attributable to the commencement of crude oil sales and other gathering services upon closing of the Black Diamond Acquisition, the commencement of gathering services in the Mustang IDP area during 2018, and an increase in gathered volumes in the Delaware Basin resulting from an increase in the number of wells connected to our gathering systems subsequent to third quarter 2017.

Fresh Water Delivery Fresh Water Delivery revenues increased during third quarter 2018 as compared with third quarter 2017 and during the first nine months of 2018 as compared with the first nine months of 2017. The increases were primarily attributable to fresh water deliveries in the Mustang IDP area resulting from well completion activity by Noble as well as an increase in fresh water deliveries to a third party customer in the Greeley Crescent IDP area. The increases were partially offset by decreased fresh water deliveries in the Wells Ranch and East Pony IDP areas resulting from well completion activity by Noble.

25

Costs and Expenses

Costs and expenses were as follows:

(in thousands)	2018		2017		Increase from Prior Year
Three Months Ended September 30,
Cost of Crude Oil Sales	$	44,379	$	—	N/M
Direct Operating	23,955		13,712		75	%
Depreciation and Amortization	18,376		3,562		416	%
General and Administrative	4,204		3,087		36	%
Total Operating Expenses	$	90,914	$	20,361	347	%
Nine Months Ended September 30,
Cost of Crude Oil Sales	$	105,830	$	—	N/M
Direct Operating	59,496		39,406		51	%
Depreciation and Amortization	46,076		8,483		443	%
General and Administrative	19,626		9,281		111	%
Total Operating Expenses	$	231,028	$	57,170	304	%

N/M Amount is not meaningful

Costs and Expenses Trend Analysis

Cost of Crude Oil Sales Cost of crude oil sales is recorded within our Gathering Systems reportable segment. The purchase and sale of crude oil commenced upon closing of the Black Diamond Acquisition during first quarter 2018.

Direct Operating Direct operating expense increased during third quarter 2018 as compared with third quarter 2017 and during the first nine months of 2018 as compared with the first nine months of 2017. The increases in direct operating expense by reportable segment were as follows:

Gathering Systems Gathering Systems direct operating expense increased during third quarter 2018 as compared with third quarter 2017 and during the first nine months of 2018 as compared with the first nine months of 2017. The increases were primarily attributable to operating expenses associated with the CGFs in the Delaware Basin that were completed subsequent to third quarter 2017, operating expenses associated with the facilities acquired in the Black Diamond Acquisition, and operating expenses associated with the commencement of gathering services in the Mustang IDP area during 2018.

Fresh Water Delivery Fresh Water Delivery direct operating expense decreased during third quarter 2018 as compared with third quarter 2017 and during the first nine months of 2018 as compared with the first nine months of 2017. The decrease during third quarter 2018 as compared with third quarter 2017 was primarily attributable to a decrease in the use of third party services. The decrease during the first nine months of 2018 as compared with the first nine months of 2017 was primarily attributable to decreased volumes resulting from the timing of well completion activity by Noble in the Wells Ranch and East Pony IDP areas and decreased use of third party services.

Depreciation and Amortization Depreciation and amortization expense increased during third quarter 2018 as compared with third quarter 2017 and during the first nine months of 2018 as compared with the first nine months of 2017. The increases in depreciation and amortization expenses by reportable segment were as follows:

Gathering Systems Gathering Systems depreciation and amortization expense increased during third quarter 2018 as compared with third quarter 2017 and during the first nine months of 2018 as compared with the first nine months of 2017. The increases were due, in part, to assets placed in service after September 30, 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 CGFs, and assets acquired in the Black Diamond Acquisition. Additionally, depreciation and amortization expense includes the amortization of intangible assets that consist of customer contracts and relationships acquired in the Black Diamond Acquisition.

Fresh Water Delivery Fresh Water Delivery depreciation and amortization expense remained consistent during third quarter 2018 as compared with third quarter 2017 and during the first nine months of 2018 as compared with the first nine months of 2017. Fresh Water Delivery depreciation and amortization expense has remained consistent, as our fresh water delivery infrastructure was substantially complete prior to 2018. See Liquidity and Capital Resources – Capital Requirements.

26

General and Administrative Expense General and administrative expense is recorded within our Investments and Other reportable segment. General and administrative expense increased during third quarter 2018 as compared with third quarter 2017 and during the first nine months of 2018 as compared with the first nine months of 2017. The increases are due primarily to legal and financial advisory transaction expenses associated with the Black Diamond Acquisition as well as other professional fees. Transaction expenses associated with the Black Diamond Acquisition during third quarter 2018 and the first nine months of 2018 were approximately $0.3 million and $7.5 million, respectively.

Other (Income) Expense Trend Analysis

(in thousands)	2018			2017			Increase (Decrease) From Prior Year
Three Months Ended September 30,
Other (Income) Expense
Interest Expense	$	4,860		$	1,493		226	%
Capitalized Interest	(1,354		)	(899		)	51	%
Interest Expense, Net	3,506			594			490	%
Investment Income	(3,866		)	(1,633		)	137	%
Total Other (Income) Expense	$	(360	)	$	(1,039	)	(65	)%
Nine Months Ended September 30,
Other (Income) Expense
Interest Expense	$	11,524		$	2,471		366	%
Capitalized Interest	(5,304		)	(1,510		)	251	%
Interest Expense, Net	6,220			961			547	%
Investment Income	(10,825		)	(4,339		)	149	%
Total Other (Income) Expense	$	(4,605	)	$	(3,378	)	36	%

Interest Expense, Net Interest expense is recorded within our Investments and Other reportable segment. Interest expense represents interest incurred in connection with our revolving credit facility and term loan credit facility. Our interest expense includes interest on outstanding balances on the facilities and commitment fees on the undrawn portion of our revolving credit facility as well as the non-cash amortization of origination fees. A portion of the interest expense is capitalized based upon construction-in-progress activity during the year. See Note 5. Property, Plant and Equipment for our Construction-in-Progress balances as of September 30, 2018 and December 31, 2017.

Interest expense and capitalized interest increased during third quarter 2018 as compared with third quarter 2017 and during the first nine months of 2018 as compared with the first nine months of 2017. The increases were due to the increased outstanding long-term debt during 2018 as compared with 2017. During 2018, we have utilized proceeds from long-term debt to fund portions of our construction activities and the Black Diamond Acquisition. In addition, the interest rates have continued to increase during both the third quarter and the first nine months of 2018.

Investment Income Investment income is recorded within our Investments and Other reportable segment. Investment income increased during third quarter 2018 as compared with third quarter 2017 due to higher earnings from our investment in the Advantage Joint Venture resulting from increased crude oil throughput volumes during third quarter 2018 as compared with third quarter 2017. Investment income increased during the first nine months of 2018 as compared with the first nine months of 2017 due to a full period of activity from the Advantage Joint Venture which closed during second quarter 2017.

State Income Tax Provision

We are not a taxable entity for U.S. federal income tax purposes or for the majority of states that impose an income tax. Due to our operations in the Delaware Basin, we are subject to a Texas margin tax. Our operations commenced during the third quarter of 2017 and we have recorded de minimis state income tax provisions during each period subsequent to commencement.

27

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, transaction expenses, 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.

28

Reconciliation of Non-GAAP Financial Measures

The following tables present reconciliations of Adjusted EBITDA and distributable cash flow from 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

	Three Months Ended September 30,					Nine Months Ended September 30,
(in thousands)	2018			2017		2018		2017
Reconciliation from Net Income
Net Income and Comprehensive Income	$	48,703		$	43,756	$	132,281	$	117,383
Add:
Depreciation and Amortization	18,376			3,562		46,076		8,483
Interest Expense, Net of Amount Capitalized	3,506			594		6,220		961
State Income Tax Provision	(94		)	33		163		33
Transaction and Integration Expenses	301			—		7,550		—
Unit-Based Compensation	343			248		1,057		581
Adjusted EBITDA	71,135			48,193		193,347		127,441
Less:
Adjusted EBITDA Attributable to Noncontrolling Interests	11,784			2,188		31,060		21,055
Adjusted EBITDA Attributable to Noble Midstream Partners LP	59,351			46,005		162,287		106,386
Less:
Cash Interest Paid	4,728			1,351		11,165		2,119
Maintenance Capital Expenditures	5,406			3,952		14,718		9,004
Distributable Cash Flow of Noble Midstream Partners LP	$	49,217		$	40,702	$	136,404	$	95,263

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

	Three Months Ended September 30,						Nine Months Ended September 30,
(in thousands)	2018			2017			2018		2017
Reconciliation from Net Cash Provided by Operating Activities
Net Cash Provided by Operating Activities	$	62,864		$	49,830		$	167,936	$	124,357
Add:
Interest Expense, Net of Amount Capitalized	3,506			594			6,220		961
Changes in Operating Assets and Liabilities	1,981			(2,583		)	7,952		1,557
Transaction and Integration Expenses	301			—			7,550		—
Change in Income Tax Payable	(94		)	33			163		33
Other Adjustments	2,577			319			3,526		533
Adjusted EBITDA	71,135			48,193			193,347		127,441
Less:
Adjusted EBITDA Attributable to Noncontrolling Interests	11,784			2,188			31,060		21,055
Adjusted EBITDA Attributable to Noble Midstream Partners LP	59,351			46,005			162,287		106,386
Less:
Cash Interest Paid	4,728			1,351			11,165		2,119
Maintenance Capital Expenditures	5,406			3,952			14,718		9,004
Distributable Cash Flow of Noble Midstream Partners LP	$	49,217		$	40,702		$	136,404	$	95,263

29

LIQUIDITY AND CAPITAL RESOURCES

Financing Strategy

Our primary sources of liquidity are cash flows generated from operations based on commercial agreements with Noble and our third party customers. We expect our ongoing sources of liquidity to include cash generated from operations, borrowings under our revolving credit facility and issuances of additional equity or debt securities. We believe that cash generated from these sources will be sufficient to meet our short-term working capital requirements and long-term capital expenditure requirements and to make quarterly cash distributions. We do not have any commitment from Noble or our general partner or any of their respective affiliates to fund our cash flow deficits or provide other direct or indirect financial assistance to us. Certain consolidated subsidiaries make distributions to or receive contributions from Noble in proportion to Noble’s ownership in the subsidiary.

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

Available Liquidity

Information regarding liquidity was as follows:

(in thousands)	September 30, 2018		December 31, 2017
Cash, Cash Equivalents, and Restricted Cash (1)	$	19,152	$	55,531
Amount Available to be Borrowed Under Our Revolving Credit Facility (2)	750,000		265,000
Available Liquidity	$	769,152	$	320,531

⁽¹⁾  See Item 1. Financial Statements – Note 2. Basis of Presentation.

⁽²⁾  See Item 1. Financial Statements – Note 7. Long-Term Debt. There was no available borrowing capacity under our term loan credit facility as of September 30, 2018.

Revolving Credit Facility and Term Loan Credit Facility

On January 31, 2018, in connection with the closing of the Black Diamond Acquisition, we entered into an amendment to increase the capacity on our revolving credit facility from $350 million to $530 million. On March 9, 2018, we entered into an additional amendment to extend the maturity of our revolving credit facility and increase the borrowing capacity to $800 million. The revolving credit facility is available to fund working capital and to finance acquisitions and expansion capital expenditures. During the the first nine months of 2018, we utilized our revolving credit facility to fund portions of our construction activities and the Black Diamond Acquisition. See Item 1. Financial Statements – Note 3. Acquisition. As of September 30, 2018, $50 million was outstanding under our revolving credit facility. See Item 1. Financial Statements – Note 7. Long-Term Debt.

On July 31, 2018, we entered into the term loan credit facility that permitted aggregate borrowings of up to $500 million. During August 2018, we drew $500 million under the term loan credit facility and used the proceeds to repay a portion of the outstanding borrowings under our revolving credit facility and pay fees and expenses in connection with the term loan credit facility transactions. See Item 1. Financial Statements – Note 7. Long-Term Debt.

Cash Flows

Summary cash flow information was as follows:

	Nine Months Ended September 30,
(in thousands)	2018			2017
Total Cash Provided By (Used in)
Operating Activities	$	167,936		$	124,357
Investing Activities	(1,190,265		)	(253,218		)
Financing Activities	985,950			82,122
Decrease in Cash, Cash Equivalents, and Restricted Cash	$	(36,379	)	$	(46,739	)

Operating Activities Net cash provided by operating activities increased during the first nine months of 2018 as compared with the first nine months of 2017 primarily due to an increase of net income driven by increased revenues resulting from higher throughput volumes due to expansion of existing systems and providing services to new areas and customers. The increase in revenues was partially offset by an increase in direct operating expenses resulting from providing services to new

30

areas and customers as well as an increase in general and administrative expense due to legal and financial advisory fees associated with the Black Diamond Acquisition.

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

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

Off-Balance Sheet Arrangements

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

Contractual Obligations

We had no material changes in our contractual commitments and obligations from amounts listed under Item 7. Management's Discussion and Analysis of Financial Conditions and Results of Operations - Liquidity and Capital Resources - Contractual Obligations in our Annual Report on Form 10-K for the year ended December 31, 2017.

Capital Requirements

Capital Expenditures and Other Investing Activities

The midstream energy business is capital intensive, requiring the maintenance of existing gathering systems and other midstream assets and facilities and the acquisition or construction and development of new gathering systems and other midstream assets and facilities. Capital expenditures and other investing activities (on an accrual basis) were as follows:

	Nine Months Ended September 30,
(in thousands)	2018		2017
Gathering System Expenditures (1)	$	669,908	$	239,054
Fresh Water Delivery System Expenditures	18,711		14,721
Total Capital Expenditures	$	688,619	$	253,775
Additions to Investments	$	426	$	68,504

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

For the nine months ended September 30, 2018, our gathering system expenditures were primarily associated with the construction of the Mustang gathering system and construction of CGFs in the Delaware Basin. Additionally, our gathering system expenditures include the Black Diamond Acquisition as well as expenditures related to the connection of the acquired system to a major oil takeaway outlet in the DJ Basin. Fresh water delivery system expenditures were primarily associated with the expansion of the the Mustang fresh water delivery system.

For the nine months ended September 30, 2017, our gathering system expenditures were primarily associated with the construction of the Greeley Crescent, Delaware Basin and Mustang gathering systems, expansion of the Wells Ranch gathering system and construction of the connection from the Billy Miner I CGF in the Delaware Basin to the Advantage pipeline. Fresh water delivery system expenditures were primarily associated with the construction of the Greeley Crescent fresh water delivery system and expansion of the Mustang fresh water delivery system.

For the nine months ended September 30, 2018, additions to investments were related to a capital call for our White Cliffs Interest. For the nine months ended September 30, 2017, additions to investments were related to our investment in the Advantage Joint Venture.

Cash Distributions

Our partnership agreement requires that we distribute all of our available cash quarterly. Quarterly distributions, if any, will be made within 45 days after the end of each calendar quarter to holders of record on the applicable record date.

31

On October 25, 2018, the board of directors of our general partner declared a quarterly cash distribution of $0.5597 per unit. The distribution will be paid on November 13, 2018, to unitholders of record as of November 5, 2018. Also on November 13, 2018, a cash incentive distribution of $1.5 million will be made to Noble related to its IDRs, based upon the level of distribution paid per Common Unit and Subordinated Unit.

For future quarters, the minimum quarterly distribution of $0.375 per unit equates to $14.8 million per quarter, or $59.4 million million per year, based on the number of Common Units and Subordinated Units outstanding as of September 30, 2018.

We expect that if we are successful in executing our business strategy, we will grow our business in a steady and sustainable manner and distribute to our unitholders a portion of any increase in our cash available for distribution resulting from such growth. We expect our general partner may cause us to establish reserves for specific purposes, such as major capital expenditures or debt service payments, or may choose to generally reserve cash in the form of excess distribution coverage from time to time for the purpose of maintaining stability or growth in our quarterly distributions. In addition, our general partner may cause us to borrow amounts to fund distributions in quarters when we generate less cash than is necessary to sustain or grow our cash distributions per unit. Our cash distribution policy reflects a judgment that our unitholders will be better served by our distributing rather than retaining our cash available for distribution. The board of directors of our general partner has considerable discretion to determine the amount of our available cash each quarter. In addition, the board of directors of our general partner may change our cash distribution policy at any time.

Item 3.    Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk

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

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

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

Interest Rate Risk

Our primary exposure to interest rate risk results from outstanding borrowings under our revolving credit facility and term loan credit facility, which have variable interest rates. As of September 30, 2018, $50 million and $500 million were outstanding under our revolving credit facility and term loan credit facility, respectively. A 1.0% increase in our interest rates would have resulted in an estimated $3.5 million increase in interest expense for the nine months ended September 30, 2018. As a result, our results of operations, cash flows and financial condition and, as a further result, our ability to make cash distributions to our unitholders, could be adversely affected by significant increases in interest rates.

Seasonality

Demand for crude oil and natural gas generally decreases during the spring and fall months and increases during the summer and winter months. However, seasonal anomalies such as mild winters or mild summers sometimes lessen this fluctuation. In addition, certain crude oil and natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer. This can also lessen seasonal demand fluctuations. These seasonal anomalies can increase demand for crude oil and natural gas during the summer and winter months and decrease demand for crude oil and natural gas during the spring and fall months. With respect to our completed midstream systems, we do not expect seasonal conditions to have a material impact on our throughput volumes. Severe or prolonged winters may, however, impact our ability to complete additional well connections or construction projects, which may impact the rate of our growth. In addition, severe winter weather may also impact or slow the ability of Noble and our third party customers to execute their drilling and development plans.

Disclosure Regarding Forward-Looking Statements

This quarterly report on Form 10-Q 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

32

“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 our control and difficult to predict, and not all of which can be disclosed in advance. We believe that we have chosen these assumptions or bases in good faith and that they are reasonable. You are cautioned not to place undue reliance on any forward-looking statements. You should also understand that it is not possible to predict or identify all such factors 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;

• 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 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-Q.

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 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 in our Annual Report on Form 10-K for the year ended December 31, 2017, which describe factors that could cause our actual results to differ from those set forth in the forward-looking statements. Our Annual Report on Form 10-K for the year ended December 31, 2017 is available on our website at www.nblmidstream.com.

33

Item 4.     Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Based on the evaluation of our disclosure controls and procedures by our principal executive officer and our principal financial officer, as of the end of the period covered by this quarterly report, each of them has concluded that our disclosure controls and procedures (as defined in Rule 13a-15(e) and Rule 15d-15(e) under the Securities Exchange Act of 1934, as amended (Exchange Act)), were effective as of the end of the period covered by this report.

Changes in Internal Control over Financial Reporting

There were no changes in internal control over financial reporting (as defined in Exchange Act Rule 13a-15(f) and 15d-15(f)) that occurred during the quarter covered by this report that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Part II. Other Information

Item 1. Legal Proceedings

Information regarding legal proceedings is set forth in Part I. Financial Information, Item 1. Financial Statements -Note 12. Commitments and Contingencies of this Form 10-Q, which is incorporated by reference into this Part II. Item 1.

Item 1A. Risk Factors

There have been no material changes from the risk factors disclosed in Item 1A. Risk Factors of our Annual Report on Form 10-K for the year ended December 31, 2017, other than the following:

Colorado Proposition #112, if approved by voters on November 6, 2018, could significantly limit, or in some cases prevent, the future development of crude oil and natural gas in areas where we currently conduct operations.

Current regulations in the state of Colorado require oil and gas development to maintain a 500-foot set-back from certain structures and a 1,000-foot set-back from certain high-occupancy buildings. However, on November 6, 2018, Colorado voters will decide whether to adopt Proposition #112, which, if passed, would increase the set-back zone for new “oil and gas development” to 2,500 feet. The term “oil and gas development” in Proposition #112 is defined to include oil and gas exploration, drilling, production and processing activities, as well as hydraulic fracturing, the reentry of an oil or gas well previously plugged or abandoned, flowlines and the treatment of waste associated with such exploration, drilling, production and processing activities. As proposed under Proposition #112, the set-back increase would be applicable to “occupied structures” and “vulnerable areas”. “Vulnerable areas” is defined to include playgrounds, permanent sports fields, public parks and open spaces, public drinking water sources, reservoirs, lakes, rivers, perennial and intermittent streams, creeks, and any other area designated as such by the state or local government; however, the proposition provides no guidance on when or how such governments may exercise this authority. If adopted, Proposition #112 is expected to take effect upon official certification of election results, to be self-executing, and to apply to new oil and gas development that is permitted on or after the date of certification; it is not expected to apply to previously permitted wells, including drilled but uncompleted wells. The Colorado Oil and Gas Conservation Commission estimates that adoption of Proposition #112 would result in approximately 85% of Colorado's non-federal land surface becoming unavailable for new oil and gas development. In Weld County alone, 78% of surface land (85% of non-federal land) would appear to be off-limits to new oil and gas development.

The adoption of Proposition #112, or other regulatory measures, could significantly limit, or in some cases prevent, the future development of crude oil and natural gas in areas where we perform midstream services within the state. Such limitations or prohibitions could have a material adverse effect on our cash flows, results of operations, financial condition, and liquidity and could result in a material impairment of these assets.

34

Item 6. Exhibits

Exhibit Number	Exhibit
2.1	Advantage Pipeline Holdings LLC Subscription Agreement, dated February 12, 2017, by and among Advantage Pipeline Holdings LLC, Trinity River DevCo LLC and Plains Pipeline, L.P. (filed as Exhibit 2.1 to the Registrant’s Annual Report on Form 10-K (File No. 001-37640) filed February 14, 2017 and incorporated herein by reference).
2.2	Contribution Agreement, dated June 20, 2017, by and among the Registrant, Noble Midstream GP LLC, Noble Midstream Services, LLC, NBL Midstream, LLC and Blanco River DevCo GP LLC (filed as Exhibit 2.1 to the Registrant’s Current Report on Form 8-K (Date of Event: June 20, 2017) filed June 26, 2017 and incorporated herein by reference).
2.3	Member Interest Purchase and Sale Agreement, dated December 12, 2017, by and between Black Diamond Gathering LLC and Saddle Butte Pipeline II, LLC (filed as Exhibit 2.1 to the Registrant’s Current Report on Form 8-K (Date of Event: December 12, 2017) filed December 12, 2017 and incorporated herein by reference).
3.1	Certificate of Limited Partnership of the Registrant (filed as Exhibit 3.1 to the Registrant’s Registration Statement on Form S-1 (Registration No. 333-207560) filed October 22, 2015 and incorporated herein by reference).
3.2	Amendment to the Certificate of Limited Partnership of the Registrant (filed as Exhibit 3.2 to the Registrant’s Registration Statement on Form S-1 (Registration No. 333-207560) filed October 22, 2015 and incorporated herein by reference).
3.3	Amendment to the Certificate of Limited Partnership of the Registrant (filed as Exhibit 3.3 to Amendment No. 1 to the Registrant’s Registration Statement on Form S-1 (Registration No. 333-207560) filed November 6, 2015 and incorporated herein by reference).
3.4	First Amended and Restated Agreement of Limited Partnership of the Registrant (filed as Exhibit 3.1 to the Registrant’s Current Report on Form 8-K (Date of Event: September 14, 2016) filed September 20, 2016 and incorporated herein by reference).
3.5	Certificate of Formation of Noble Midstream GP LLC (filed as Exhibit 3.4 to the Registrant’s Registration Statement on Form S-1 (Registration No. 333-207560) filed October 22, 2015 and incorporated herein by reference).
3.6	Amendment to Certificate of Formation of Noble Midstream GP LLC (filed as Exhibit 3.5 to the Registrant’s Registration Statement on Form S-1 (Registration No. 333-207560) filed October 22, 2015 and incorporated herein by reference).
3.7	First Amended and Restated Limited Liability Company Agreement of Noble Midstream GP LLC (filed as Exhibit 3.2 to the Registrant’s Current Report on Form 8-K (Date of Event: September 14, 2016) filed September 20, 2016 and incorporated herein by reference).
10.1	Term Credit Agreement, dated as of July 31, 2018, by and among Noble Midstream Services, LLC, as borrower, the Partnership, as parent, and Toronto Dominion (Texas) LLC and the other lenders party thereto.
10.2	Guarantee Agreement, dated as of July 31, 2018, by and among Noble Midstream Services, LLC, as borrower, the Partnership, as parent, and Toronto Dominion (Texas) LLC and the other lenders party thereto.
10.3*†	Amendment 02 to that certain Second Amended and Restated Crude Oil Gathering Agreement, dated as of July 1, 2018, among Noble Energy, Inc., as Producer, and Green River DevCo LP.
10.4*†	Amendment 02 to that certain Second Amended and Restated Gas Gathering Agreement, dated as of July 1, 2018, among Noble Energy, Inc., as Producer, and Green River DevCo LP.
10.5*†	Amendment 02 to that certain Second Amended and Restated Fresh Water Services Agreement, dated as of July 1, 2018, among Noble Energy, Inc., as Producer, and Green River DevCo LP.

35

10.6*†	Amendment 02 to that certain Second Amended and Restated Produced Water Services Agreement, dated as of July 1, 2018, among Noble Energy, Inc., as Producer, and Green River DevCo LP.
10.7*	Amendment 02 to that certain Second Amended and Restated Fresh Water Services Agreement, dated as of July 1, 2018, among Noble Energy, Inc., as Producer, and Colorado River DevCo LP.
31.1*	Certification of the Company’s Chief Executive Officer Pursuant To Section 302 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 7241).
31.2*	Certification of the Company’s Chief Financial Officer Pursuant To Section 302 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 7241).
32.1*	Certification of the Company’s Chief Executive Officer Pursuant To Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350).
32.2*	Certification of the Company’s Chief Financial Officer Pursuant To Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350).
101.INS*	Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
101.SCH*	XBRL Schema Document
101.CAL*	XBRL Calculation Linkbase Document
101.LAB*	XBRL Label Linkbase Document
101.PRE*	XBRL Presentation Linkbase Document
101.DEF*	XBRL Definition Linkbase Document

*	Filed herewith.
†	Confidential treatment has been requested for certain portions thereof pursuant to a Confidential Treatment Request filed with the Securities and Exchange Commission. Such provisions have been filed separately with the Securities and Exchange Commission.

36

Signatures

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

		Noble Midstream Partners LP
		By: Noble Midstream GP, LLC,        its General Partner
Date	November 1, 2018	By: /s/ John F. Bookout, IV
		John F. Bookout, IV Chief Financial Officer

37