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www.nblmidstream.com Fourth Quarter Earnings Call February 2018 Fourth Quarter and Full Year 2017 Results 2018 Guidance Extended and Enhanced Long-Term Outlook

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Page 1: Fourth Quarter Earnings Call - investors.nblmidstream.cominvestors.nblmidstream.com/~/media/Files/N/Noble-Midstream-IR/... · Fourth Quarter Earnings Call February 2018 Fourth Quarter

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Fourth Quarter Earnings Call

February 2018

Fourth Quarter and Full Year 2017 Results

2018 Guidance

Extended and Enhanced Long-Term Outlook

Page 2: Fourth Quarter Earnings Call - investors.nblmidstream.cominvestors.nblmidstream.com/~/media/Files/N/Noble-Midstream-IR/... · Fourth Quarter Earnings Call February 2018 Fourth Quarter

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Forward Looking Statements and Non-GAAP Measures

This presentation contains certain “forward-looking statements” within the meaning of federal securities law. Words such as“anticipates”, “believes”, “expects”, “intends”, “will”, “should”, “may”, “estimates”, and similar expressions may be used to identifyforward-looking statements. Forward-looking statements are not statements of historical fact and reflect the Partnership’scurrent views about future events. No assurances can be given that the forward-looking statements contained in this newsrelease will occur as projected and actual results may differ materially from those projected. Forward-looking statements arebased on current expectations, estimates and assumptions that involve a number of risks and uncertainties that could causeactual results to differ materially from those projected. These risks include, without limitation, customers’ ability to meet theirdrilling and development plans, changes in general economic conditions, competitive conditions in the Partnership’s industry,actions taken by third-party operators, gatherers, processors and transporters, the demand for crude oil and natural gasgathering and processing services, the Partnership’s ability to successfully implement its business plan, the Partnership’s ability tocomplete internal growth projects on time and on budget, the price and availability of debt and equity financing, the availabilityand price of crude oil and natural gas to the consumer compared to the price of alternative and competing fuels, and other risksinherent in the Partnership’s business, including those described under “Risk Factors” and “Forward-Looking Statements” in thePartnership's most recent Annual Report on Form 10-K and in other reports on we file with the Securities and ExchangeCommission (“SEC”). These reports are also available from the Partnership’s office or website, www.nblmidstream.com. Forward-looking statements are based on the estimates and opinions of management at the time the statements are made. NobleMidstream does not assume any obligation to update forward-looking statements should circumstances, management’sestimates, or opinions change.

2

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Strong Execution

In-line or Exceeding Guidance Across Metrics

Fourth Quarter 2017 Highlights

3

Recent DevelopmentsIncreased 3rd Party Exposure

Black Diamond AcquisitionClosed January 31, 2018

January Advantage Nominations of ~90 MBbl/d

DPU Growth4.7% Increase Above 3Q

24% Increase Over 4Q16

30% Above MQD

Financial Discipline4Q Distribution Coverage Ratio 2.2x/2.4x 1

4Q Annualized Leverage 1.4x/1.9x 2

Growth Projects Delivered

2nd Delaware CGF Online in DecemberFWD Operational at Green River in DJ Basin

4Q Gathering Volumes vs 3Q Oil & Gas +28% Produced Water +81%

1. DCF is a Non-GAAP measure, see definition provided in appendix; 2.2x as reported; 2.4x adjusted for December equity issuance and prior to any Black Diamond acquisition contribution

2. 1.4x prior to Black Diamond acquisition and proceeds from equity issuance; 1.9x pro-forma for Black Diamond acquisition

Gathering business drives growth in key financial metrics

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Fourth Quarter 2017 Results

4

Actuals 4Q Guidance 4Q v

1Q 2Q 3Q 4Q 31-Oct-17 3Q

Oil Gathered (MBbl/d) 44 54 71 93 82 - 90 31%

Gas Gathered (MMcf/d) 113 122 146 175 165 - 180 20%

MBoe/d 63 74 95 122 110 - 120 28%

PW Gathered (MBw/d) 9 13 27 49 38 - 48 81%

FW Delivered (MBw/d) 129 184 175 135 110 - 150 -23%

per equivalent well average (NBL wells only) (1) 217 227 203 262 29%

Net Income ($MM) $35 $39 $44 $46 $43 - $47 5%

Gross Adjusted EBITDA ($MM) (2) $37 $42 $48 $52 $48 - $55 8%

Net Adjusted EBITDA ($MM) (2) $26 $34 $46 $48 $45 - $52 4%

DCF ($MM) (2) $24 $30 $41 $43 $39 - $45 5%

Distribution Coverage Ratio(2) 1.8x 1.9x 2.4x 2.2x/2.4x(3) 2.2x - 2.5x

Gross Capex ($MM) $76 $84 $94 $136 $131 - $151

Net Capex ($MM) $59 $46 $59 $62 $66 - $76

Equivalent Wells Connected(1) 31 48 147 75

In-line or exceeding guidance across metrics

1. Fresh water per equivalent well. Equivalent well defined as horizontal well normalized to 4,500 ft. 2. Figures are Non-GAAP, see definition provided in appendix3. 2.2x as reported; 2.4x adjusted for December equity issuance and prior to any Black Diamond acquisition contribution

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NBL

Third

Party

2018E50% NBL

~2.5 Rigs on Dedications

~340k Dedicated Acres~310k NBL; ~30k 3rd Party

1 Customer; 144 Equivalent Well Connects²

100% Net Adjusted EBITDA from Sponsor

Portfolio Evolution:Rosetta Oil and PW Dedication (~40k acres)

Greeley Crescent I Dedication to 3rd Party (~30k acres) for Oil, PW, FWD

~5 Rigs on Dedications

~415k Dedicated Acres~350k NBL; ~65k 3rd Party

~10 Customers; 308 Equivalent Well Connects²

91% Net Adjusted EBITDA from Sponsor

Portfolio Evolution:Rosetta Gas Dedication (~47k acres)

Clayton Williams Oil, PW, Gas Dedication (~64k acres)

Greeley Crescent II Dedication to 3rd Party (~30k acres) for Oil, PW, FW

Advantage Acquisition

Laramie River Start Up

Gas Compression Dedication Added (~110k acres)

~17 Rigs on Dedications

~555k Dedicated Acres~350k NBL; ~205k 3rd Party

15+ Customers; ~700 Equivalent Well Connects²

78% Net Adjusted EBITDA from Sponsor

Portfolio Evolution:Full Year of Laramie River

Advantage Ramp

Black Diamond Acquisition (~141k acres)

NBL

Third

Party

201764% NBL

Adding Significant Scale and Customer Diversification

NBL

2016100% NBL

Delaware and DJ Basin Gross Oil & Gas Throughput1 Mix

Advantage and Black Diamond Gathering JVs materially enhance 3rd party business

1. Includes oil and gas gathering and Advantage throughput2. Defined as horizontal well normalized to 4,500 ft.

5

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Peer-Leading Distribution Growth and Financial Strength

2018E Distribution Coverage Ratio

2018E Leverage Ratio

3-Year Distribution CAGR 2017-2020E

6

0%

5%

10%

15%

20%

25%

30%

Peer A NBLX Peer B Peer C Peer D Peer E Peer F Peer G Peer H

0.0x

0.5x

1.0x

1.5x

2.0x

2.5x

NBLX Peer B Peer A Peer D Peer C Peer E Peer F Peer G Peer H

0.0x

0.5x

1.0x

1.5x

2.0x

2.5x

3.0x

3.5x

4.0x

4.5x

Peer H Peer G Peer D Peer F NBLX Peer B Peer A Peer E Peer C

Source: NBLX represents internal forecast; Wells Fargo Midstream Monthly Outlook: January 2018 Report for peersNote: Peers Include AM, CNXM, ENLK, EQM, HESM, OMP, RMP, WES

20% distribution growth, low leverage and high coverage

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2018 Goals and Objectives

7

Positioned For Sustainable, Long–Term

Growth

20%DPU Growth 2020+

Brought Online 2 Major Projects 2st Delaware Basin CGF DJ Basin Fresh Water System for

Noble Energy

3 Acquisitions 2017 Advantage Pipeline JV 1st Dropdown Saddle Butte JV

Preserving Financial Strength

2.4x4Q Distribution Coverage 1

<1x4Q Annualized Leverage 2

Continue to Provide Safe and Reliable Service to Our Sponsor and Other Customers

Continue to Extend 20% Distribution per Unit Growth

Generate Corporate ROACE(1) Greater than 15% for 2018

Complete Growth Projects on Time/Budget

Completion of 3 Delaware CGFs

Green River infrastructure

Black Diamond asset integration

Finalize Delaware Long Haul Pipeline Option

Execute Accretive Drop Down During 2018

Maintain Top-Tier Coverage and Leverage

Drive Additional Commercial Success Through Incremental Acreage Dedications

Growth with a focus on execution and financial strength

1. Return on average capital employed: earnings before interest and taxes divided by (average total assets – average current liabilities); see definition provided in appendix

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2018 Capital Budget Detail

8

Colorado

River

4%

Laramie

River²

29%

Green

River

13%Other

Blanco

River

45%

Trinity

River

8%

Gross Capital1

$485 - 535MM

1. Excludes acquisition capital2. Includes Black Diamond Gathering capital; Additional detail on Black Diamond Gathering provided on slide 14

DJ Basin Delaware Basin

DevCo% Ownership

Colorado River100%

Laramie River²100%

Green River25%

Blanco River40%

Trinity River100%

Expected 2018 Capital Investment

• Gathering system well connections

• New Wells Ranch gas offload

• Gathering systemwell connections

• Multiple DSU’s for FWD

• Black Diamond capital

• Completion of Mustang backbone infrastructure

• Gathering system well connections

• Buildout of 3 CGFs• Gathering system

well connections

• Expansion of Advantage throughputcapacity to 200 MBbl/d

• Compression

Colorado

River

8%

Laramie

River²

37%

Green

River

6%Other

Blanco

River

34%

Trinity

River

15%

Net Capital1

(attributable to the Partnership)

$255 - 285MM

Growth capital focused on Blanco River and Laramie River DevCos

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Project Startups and Activity Ramp Driving 2018 Growth

9

89

200 - 235

170 - 200

230-270

0

50

100

150

200

250

300

2017 2018E 1H18E 2H18E

Oil and Gas GatheringMBoe/d

24

80 -110

60 - 80

100 - 140

0102030405060708090

100110120130

2017 2018E 1H18E 2H18E

Produced Water GatheringMBw/d

156 130 -190

120 -140

140 - 240

0

50

100

150

200

2017 2018E 1H18E 2H18E

Fresh Water DeliveryMBw/d

2Q3 Additional Delaware CGFs Online by Mid-2018; 1 per Month Starting in Mid-March

3Q

4Q

1Q

Commence Mustang Well Connects

17 Average USO Rig Exposure

>275 Miles of Pipe Installed

~ 700 Equivalent Well Connects1

Commence Mustang FWD in Late 1QBlack Diamond Close Jan 31

> 250 Equivalent Well Connects Drives Strong Q4 and Momentum into 2019

308

~ 700

~40%

~60%

-100

100

300

500

700

900

1100

1300

1500

2017 2018E 1H18E 2H18E

Equivalent Wells Connections1

Consistent milestones and catalysts throughout the year

1. Defined as horizontal well normalized to 4,500 ft.

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Net Income Guidance of $220 - $260 MM, or 46% Above 2017

45% Annual Adjusted Net EBITDA1 Growth Anticipated at Guidance Midpoint ($215 - $235 MM)

Decline in Adjusted Net EBITDA1 from 1Q18E to 2Q18E due to development timing, lower FWD volumes and customer completion operations shift from Colorado River (100% owned) to Green River (25% owned)

Advantage Volume Growth Drives >100% Increase in Income from Investments

20% Distribution Growth with Distribution Coverage1 Ratio of 1.9x –2.1x1

2018 Growth in Adjusted EBITDA and Distributions

10

$155

$215-235

$100-$110$115-125

0

50

100

150

200

250

300

2017 2018E 1H18E 2H18E

$225-245

2.1x 1.9x-2.1x

$1.81

$2.19

.x

.5x

1.x

1.5x

2.x

2.5x

.x

.5x

1.x

1.5x

2.x

2.5x

3.x

3.5x

4.x

4.5x

2017 2018E

2H18 growth reflects Delaware CGF and customer activity timing

1. Figures are Non-GAAP, see definition provided in appendix; 2018 EBITDA estimates adjusted for $5 million in Black Diamond Gathering transaction expenses expected in 1Q182. Defined as horizontal well normalized to 4,500 ft. ; freshwater per equivalent well of 200 MBw and 260 MBw is for NBL wells only3. Assumes 20% distribution growth target

Upside Sensitivity: Assumes 4Q17 FWD per Equivalent Well of ~260 MBw²

Base Guidance: Assumes FWD per Equivalent Well of 200 MBw²

Net Adjusted EBITDA ($MM)¹ Distribution Coverage Ratio1,3 & DPU

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Extending Leading Long-Term Outlook

11

Organic – No Drop Downs2017-2020E 2018E 2019-2022E

Old New New

Distribution per Unit 20% 20% 20%

Coverage (in all years) (1) > 1.3x 1.9 – 2.1x > 1.3x

Leverage (in all years) < 2.5x < 2.5x < 2.0x

ROACE (1, 3) NA > 15% 13 – 16%

DCF Funding % of Capex and Distributions (4) NA ~50%

~90% (cumulative)

1. Non-GAAP measures, definition provided in appendix2. Reflects combined Black Diamond, Advantage, and 2017 drop-down net acquisition cost divided by net EBTIDA; definition of EBITDA provided in appendix3. Return on average capital employed: earnings before interest and taxes divided by (average total assets – average current liabilities); see definition provided in appendix4. % of distributions + capex funded by distributable cash flow

Substantial organic growth with large existing drop-down inventory

Material Upside to Improved Outlook

Prudent Commodity Price View: Based on $50/Bbl and $3/McfPrice Deck vs. Current Strip

Continued Business Development Success, Leveraging Asset Footprints

EPIC Crude / Y-Grade Project Options and Other Long-Haul

Significant and Growing Drop-Down Inventory

45%of acreage dedications

from 3rd parties

~90%% of distributions + capex

covered by DCF¹ 2019-2022E (cumulative) in organic base

plan

~6x(2)

combined adjusted EBITIDA¹ acquisition multiple by 2020E

ROACE(1,3)

2018: >15% Long-Term: 13 - 16%

Extending and improving long-term distribution growth, coverage, and

leverage

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Advantage Pipeline: Rapid Integration and Value Creation

12

4Q17 Volumes of ~60 MBbl/d, 2x Growth Since Acquisition Close

January Nominations of ~90 MBbl/d

Multiple Drivers of Recent Increased Volumes

Basin-wide volume ramp

Recent commercial success with new shippers

Constraints on competitor systems

Additional Upside Opportunities Currently Being Negotiated

Opportunities for additional acreage dedications and volume commitments

Leverages asset footprint with minimal capital required

Accelerated EBITDA1 Multiple Compression to Less than 5.5x in 2018

2018 volumes benefit from NBL activity ramp

Evaluating Growth Opportunities for Intermediate Gathering Segment in Delaware

NBL Clayton Williams dedication

Additional acreage dedication opportunities

30

60

90

90-100

0

20

40

60

80

100

120

Apr-17 4Q17 Jan-18 2018E

~14.0x NTM EBITDA1

Highlighting recent commercial success and the benefits of a Sponsor MLP

Attractive entry multiple as well as unique multiple

compression for recent Permian midstream acquisition1. Figures are Non-GAAP, see definition provided in appendix2. April 1, 2017 transaction close; includes actuals for 2Q 2017 through 4Q 2017 and latest forecast for 1Q 2018

Recent Developments

Acquisition Case Current View

~9.0x NTM EBITDA1,2

~6.0x 2018 EBITDA1

<5.5x 2018 EBITDA1

Additional upside

opportunities under

negotiation

Advantage Pipeline Oil Throughput (MBbl/d)

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4Q Oil and Gas Gathering Volumes of ~15 MBoe/d, ~3x volumes in 3Q

Full quarter of 10 wells connected into Billy Miner I

December contribution from Jesse James - 11 wells currently connected

2018 Projects Drive Significant Operating Leverage

90 MBbl/d of Crude Oil Capacity from 5 CGFs Planned to be Operational by Mid-2018

Applying lessons learned from Billy Miner I and Jesse James to drive down infrastructure costs

Coronado and Billy Miner II construction initiated

Collier site clearing and prep complete

3 1H18 CGFs remain on schedule and budget

Significant Capital Efficiency Expected in 2019 Once Backbone Infrastructure is Complete

Near-Term Delaware Basin CGF Projects

Daily Capacity

Oil (MBbl/d)

Gas(MMcf/d)

PW(MBw/d)

Est. Online

#1 Billy Miner I 15 30 30 Online

#2 Jesse James 15 30 30 Online

#3 Coronado * 20 30 60 1H 2018

#4 Billy Miner II 20 30 60 1H 2018

#5 Collier * 20 30 60 1H 2018

Blanco River Projects Update

Jesse James CGF

* expandable to 30 MBbl/d and 60 MMcf/d with minimal equipment additions

Significant 2018 growth driver

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Black Diamond Gathering

14

Acquisition of Saddle Butte Pipeline Closed on January 31st

Highly Strategic Asset

Complementary to existing infrastructure

Connectivity to every DJ downstream takeaway option

Significant undedicated acreage in catchment area

Project Return Competitive with Existing Portfolio

4.4% economic promote to NBLX

$70 million in capital avoidance over 2 years

Including promote, NBLX NTM² acquisition multiple of ~13.5x

Expect EBITDA multiple compression to < 8.0x in 2020 without any contribution from Sponsor acreage position

Significant Upside and Multiple Compression Beyond Acquisition Case

PDCE acreage dedications increased by ~24k net acres at close

Levering existing NBL dedications and sponsor throughput through time

Joint commercial efforts underway for additional dedications

Potential addition of complementary services, including storage

141k(1)

net acreage dedications from 3rd parties

6-7total rigs operating in

2018

> 75 MBbl/d2018E exit throughput

Strong base project returns with upside potential

(1) Includes PDCE Energy dedication expansion to ~96,000 net acres (2) NTM period beginning February 2018; Noble Midstream received a 4.4% ownership promote

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DJ Basin Projects Update

15

Greeley Crescent (Laramie River DevCo):

4Q Oil Gathering Averaged ~16 MBbl/d, up ~3x vs. 3Q from Additional Well Connects

Connecting of Existing Oil System into Black Diamond Storage Terminals Already Underway

Wells Ranch and East Pony (Colorado River DevCo):

4Q Oil and Gas Gathering of 92 MBoe/d, 8% Above 3Q

Upstream Results Continue to Outperform NBLX Expectations

~30% Oil and Gas Gathering Growth in 2017 on ~$30 million in Capital

Mustang (Green River DevCo):

Expanded Fresh Water System Online in December 2017

Fresh water delivery anticipated in late 1Q18

Construction Underway on Backbone Gathering Infrastructure

Gathering volumes anticipated mid-year 2018

Spec Gathering System

Planned Oil Connection into Black Diamond Milton Terminal

Full Infrastructure Build Out Includes ~250 Miles of Pipelines (Oil, Gas, PW and FW)

Development Drilling and Row Concept in Southern Portion of Mustang Drives Highly Efficient Infrastructure Spend from the Start

Greely Crescent Infrastructure Design

Legacy Third-Party Acreage Dedication

Third-Party Acreage (Formerly NBL)

NBL Acreage

LARAMIE RIVER DEVCO

GUNNISON RIVER DEVCO

Mustang Infrastructure Design

Laramie River and Green River drive 2018 throughput growth

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37

48

$37

Gathering EBITDA =G2 Actual FW

Distribution Coverage1 of 4Q Distribution

Gathering EBITDA

4Q 2017 NBLX Net EBITDA and Distribution Coverage (1,2)

Total EBITDA

Implied Distribution Coverage of 4Q Distribution

x

2.2x

1. Figures are Non-GAAP; see definition in Appendix2. G&A allocated to gathering and freshwater delivery based on proportionate share of EBITDA; coverage figures reflect full net maintenance capital totals

16

1.6x

4Q Gathering EBITDA1 of $37 MM, a 19% Increase Above 3Q

1.6x Distribution Coverage Ratio1 excluding Fresh Water

Gathering EBITDA attributable to the Partnership contributing 77% of total EBITDA attributable to the Partnership as compared to 67% in 3Q

Gross Fresh Water Volumes are Expected to Grow 3% in 2018 vs. 2017

2018 budget assumes fresh water per equivalent well of 200 MBw

Risked customer activity ramp for 2H18

$ in millions

89

196

227

262

0

50

100

150

200

250

300

2015 2016 2017 4Q17

MBw

Fresh Water per Equivalent Well (NBL Wells Only)

Fresh Water Delivery EBITDA

Conservative planning for Fresh Water

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2018 Guidance Detail

17

2017 2018 Estimates1

4Q Full Year 1Q Full Year

Gro

ss V

olu

me

s

Oil Gathered (MBbl/d) 93 66 120 -135 160 - 190

Gas Gathered (MMcf/d) 175 139 190 - 200 220 - 270

Oil and Gas Gathered (MBoe/d) 122 89 152 - 168 200 - 235

Produced Water Gathered (MBw/d) 49 24 42 - 50 80 - 110

Fresh Water Delivered (MBw/d) 135 156 130 - 150 130 - 190

Fin

an

cia

ls (

$M

M)

(1)

Net Income 46 164 42 - 48 220 - 260

Adjusted Gross EBITDA3,4 52 179 55 - 61 275 - 315

Adjusted EBITDA3,4 48 155 52 - 58 215 - 235

Distributable Cash Flow³ 43 138 44 - 50 180 - 195

Distribution Coverage Ratio 3,5 2.2x/2.4x7 2.1x 2.1x - 2.4x 1.9x - 2.1x

Gross Capex6 136 390 225 - 250 485 - 535

Net Capex 6 62 225 110 - 125 255 - 285

Equivalent Wells Connected² 82 308 120 - 140 ~700

1. Black Diamond Gathering contribution included for period following January 31, 2018 close2. Defined as horizontal well normalized to 4,500 ft.3. Includes Non-GAAP measures; see definition in Appendix4. 1Q18 and 2018 Adjusted for $3.5 MM in Black Diamond transaction expenses not capitalized5. Estimates include forecasted DPU growth of 4.7% quarterly, or 20% annual6. Excludes acquisition capital7. 2.2x as reported; 2.4x adjusted for December 2017 equity offering prior to any Black Diamond acquisition contribution

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2018 Gross Volume Guidance

18

2017 2018 (E) 1

Oil & Gas Gathered(MBoe/d)

Produced Water

Gathered(MBw/d)

FreshWater

Delivered(MBw/d)

Oil & Gas Gathered(MBoe/d)

Produced Water

Gathered(MBw/d)

FreshWater

Delivered(MBw/d)

De

vC

o

Colorado River 78 14 84 80 – 90 14 – 17 40 – 60

Laramie River 6 2 37 73 – 82 3 – 5 40 – 50

Blanco River 5 8 - 40 – 50 60 – 79 -

Green River - - - 7 –13 3 – 9 50 – 80

San Juan River - - 35 - - -

Trinity River3 - - - - -

Total 89 24 156 200 - 235 80 - 110 130 - 190

MBbl/d MBbl/d

Advantage Pipeline² 43 90 - 100

Project start-ups in 2H 2018 driving full year growth

1. Black Diamond Gathering contribution included in Laramie River DevCo for period following January 31, 2018 close2. Excluded from total throughput due to accounting treatment as investment income; throughput average from April – Dec 20173. Gas volumes from Trinity River compression segment reflected in Blanco River

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Significant Dropdown Inventory Supplements Organic Growth

19

Current Status of Asset Acreage

NBLRetainedInterest

• Blanco River (Delaware Basin) 60% Operational 111,000

• Green River (DJ Basin – Mustang IDP) 75% In Progress 75,000

• Gunnison River (DJ Basin – Bronco IDP) 95% Undeveloped 36,000

• San Juan River (DJ Basin - East Pony Fresh Water) 75% Operational 44,000

Wholly Retained Assets

• Legacy CWEI Infrastructure Assets Operational N/A

• East Pony Gas Gathering• East Pony Gas Processing

Operational 44,000

• Eagle Ford Gathering Operational 31,000

Other ROFRServices

• Delaware Basin Salt Water Disposal• Delaware Basin Fresh Water Delivery

In Progress 111,000

• Crude Oil Gathering, Natural Gas Gathering and Water Services ROFR on all future acquired onshore acreage in U.S. (outside of Marcellus Shale)

Continue to target one dropdown per year from significant inventory

CWEI Oil Transmission Dedication

Third-Party Business Development in DJ Basin and Delaware Basin

Delaware Basin Long-Haul Pipeline Opportunities

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Strategy

20

Continuous focus on safety culture

Customer service mentality for NBL and 3rd parties

Execute on “back-yard” opportunities

Preserve prudent long-term leverage and coverage

20% distribution per unit growth rate through 2020+

Effectively manage and optimize dropdown inventory

50% Permian EBITDA contribution by 2020

Increase Permian Exposure

Execute Dropdowns

Distribution Growth

Disciplined Financial Principals

Increase 3rd Party Business

Customer Service

Safety

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4+ BBoe Net Unrisked Resources in Top Tier U.S. Unconventional Basins

~6,500 future drilling locations

Robust 2018 Outlook

US Onshore volumes up >20% vs. 2017 on flat capital, with growth driven primarily by the Delaware Basin

Nearly 70% of 2018E total capital allocation to U.S. onshore

7.5 operated rigs throughout 2018 in the DJ and Delaware Basins

U.S. Onshore Combined CAGR of 25% 2018-2020E, Led by Delaware and DJ Basin

CAGR of >75% 2018-2020E in Delaware Basin

CAGR of >15% 2018-2020E in DJ Basin

Strong Financial Position and Flexibility

Investment grade credit rating at all three rating agencies

$1.5 B in cumulative excess cash flow created 2018-2020E at $50/Bbl oil ($3 B at strip)

About Our Sponsor

21

Robust NBL upstream outlook reinforces NBLX long-term objectives

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Appendix

22

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NBLX Asset Map: DJ Basin

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Black Diamond (54.4%) 1

Dedicated Acres: 141k2

Laramie River DevCo (100%)• Oil Gathering

Area: East PonyDedicated Acres: 44k

Colorado River DevCo (100%)• Oil Gathering

San Juan River DevCo (25%)• FW Delivery

Area: MustangDedicated Acres: 75k

Green River DevCo (25%)• Oil Gathering• Gas Gathering• PW Gathering• FW Delivery

Area: Wells RanchDedicated Acres: 78k

Colorado River DevCo (100%)• Oil Gathering• Gas Gathering• PW Gathering• FW Delivery

Area: Greeley CrescentDedicated Acres: 65k

Laramie River DevCo (100%)• Oil Gathering• PW Gathering• FW Delivery

Area: BroncoDedicated Acres: 36k

Gunnison River DevCo (5%)• Oil Gathering• PW Gathering• FW Delivery

1. Acquisition closed January 31, 20182. Reflects expansion of PDC Energy acreage dedication to Black Diamond Gathering system

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NBLX Asset Map: Delaware Basin

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Area: Delaware BasinDedicated Acres: 111k

Blanco River DevCo (40%)• Oil Gathering• Gas Gathering• PW Gathering

Trinity River DevCo (100%)• HP Gas Compression

Advantage JV (50%)NBL Dedicated Acres: 47k

Trinity River DevCo (100%)• Oil Transmission

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50%

NBLX Structure

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GreenRiver

San JuanRiver

Gunnison River

ColoradoRiver

LaramieRiver

TrinityRiver

BlancoRiver

ControllingInterest

Noble MidstreamServices, LLC

Public Unitholders (LP)

White Cliffs Pipeline L.L.C.

ROFR Assets:• East Pony Gas Gathering• East Pony Gas Processing• Eagle Ford Shale Midstream• Additional DJ Acreage• Additional Delaware Basin

Services

Noble EnergyNYSE: NBL

Noble MidstreamPartners LPNYSE: NBLX

Noble Midstream GP LLC45.5% Limited

Partner Interest 1

100%

100%100%100%5%25%25%40%

75% 95%

3.33% Non-OperatingMembership Interest

54.5% LimitedPartner Interest 1

100%

Non-Economic GeneralPartner Interest

AdvantageJV

1. Reflects December 2017 equity issuance

2. Pro forma for Black Diamond Gathering acquisition

60% 75%

Black Diamond 2

Non-ControllingInterest

54.4%

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Non-GAAP Financial Measures

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This presentation includes Adjusted EBITDA, Distributable Cash Flow, Distribution Coverage Ratio and ROACE, all of which are non-GAAP measures which may be used periodically by management when discussing our financial results with investors and analysts.

We define Adjusted EBITDA as net income before income taxes, net interest expense, depreciation and amortization and unit-based compensation. Adjusted EBITDA is used as a supplemental financial measure by management and by external users of our financial statements, such as investors, industry analysts, lenders and ratings agencies, to assess: our operating performance as compared to 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 define Distributable Cash Flow as Adjusted EBITDA less estimated maintenance capital expenditures and cash interest expense. Distributable Cash Flow is used by management to evaluate our overall performance. Our partnership agreement requires us to distribute all 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 available cash that is available to our unitholders for a given period. We calculate our Distribution Coverage Ratio as Distributable Cash Flow divided by total distributions declared. The Distribution Coverage Ratio is used by management to illustrate our ability to make our distributions each quarter.

We define ROACE as earnings before interest and taxes divided by (average total assets – average current liabilities). ROACE is used by management to measure the efficiency of the utilization of the capital that we employ.

We believe that the presentation of Adjusted EBITDA, Distributable Cash Flow, Distribution Coverage Ratio and ROACE provide information useful to investors in assessing our financial condition and results of operations. The GAAP measure most directly comparable to Adjusted EBITDA, Distributable Cash Flow, Distribution Coverage Ratio and ROACE is Net Income. Adjusted EBITDA, Distributable Cash Flow, Distribution Coverage Ratio and ROACE should not be considered alternatives to net income or any other measure of financial performance or liquidity presented in accordance with GAAP. Adjusted EBITDA, Distributable Cash Flow, Distribution Coverage Ratio and ROACE exclude some, but not all, items that affect net income, and these measures may vary from those of other companies. As a result, Adjusted EBITDA, Distributable Cash Flow, Distribution Coverage Ratio and ROACE as presented herein may not be comparable to similarly titled measures of other companies.

Noble Midstream does not provide guidance on the reconciling items between forecasted Net Income, forecasted Adjusted EBITDA, forecasted Distributable Cash Flow and forecasted Distribution Coverage Ratio due to the uncertainty regarding timing and estimates of these items. Noble Midstream provides a range for the forecasts of Net Income, Adjusted EBITDA, Distributable Cash Flow and Distribution Coverage Ratio to allow for the variability in timing and uncertainty of estimates of reconciling items between forecasted Net Income, forecasted Adjusted EBITDA, forecasted Distributable Cash Flow and forecasted Distribution Coverage Ratio. Therefore, the Partnership cannot reconcile forecasted Net Income to forecasted Adjusted EBITDA, forecasted Distributable Cash Flow or forecasted Distribution Coverage Ratio without unreasonable effort.

In addition to Net Income, the GAAP measure most directly comparable to Adjusted EBITDA and Distributable Cash Flow is net cash provided by operating activities. Adjusted EBITDA and Distributable Cash Flow should not be considered alternatives to net income, net cash provided by operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Due to the forward-looking nature of net cash provided by operating activities, management cannot reliably predict certain of the necessary components of the most directly comparable forward-looking GAAP measures, such as future impairments and future changes in working capital. Accordingly, Noble Midstream is unable to present a quantitative reconciliation of the aforementioned forward-looking non-GAAP financial measures to net cash provided by operating activities. Amounts excluded from these non-GAAP measures in future periods could be significant.

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Non-GAAP Reconciliation

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$ in millions 1Q 2Q 3Q 4Q FY 1Q FY

Net Income 35$ 39$ 44$ 46$ 164$ 42-48 220 - 260

Add: Depreciation and Amortization 2 2 4 4 13 6 35 - 36

Add: Interest Expense, Net of Amount Capitalized 0 0 1 1 1 1-2 13 - 14

Add: Income Tax Provision - - 0 (0) 0 - -

Add: Unit-Based Compensation 0 0 0 0 1 .2-.3 1

Add: Transaction Expenses 5 5

EBITDA 37$ 42$ 48$ 52$ 179$ 55 -61 275 - 315

Less: EBITDA Attributable to Noncontrolling Interests 11 8 2 3 24 3 60 - 80

EBITDA Attributable to NBLX 26$ 34$ 46$ 48$ 155$ 52-58 215 - 235

Less: Maintenance Capital Expenditures & Cash Interest 3 4 5 5 17 8 35-40

DCF Attributable to NBLX 24$ 30$ 41$ 43$ 138$ 44 - 50 180- 195

Distribution Coverage 1.8x 1.9x 2.4x 2.2x 2.1x 2.1x - 2.4x 1.9x - 2.1x

2017 2018E

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1001 Noble Energy WayHouston, TX 77070

Contact Information

Megan Repine

Investor Relations

[email protected]

832.639.7380