Third Quarter 2018 Earnings Call November 1, 2018 - - PowerPoint PPT Presentation

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Third Quarter 2018 Earnings Call

November 1, 2018

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Forward Looking Statements

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 identify forward-looking statements. Forward-looking statements are not statements of historical fact and reflect Noble Midstream Partners LP’s (Noble Midstream or the Partnership) current views about future events. No assurances can be given that the forward-looking statements contained in this presentation will occur as projected and actual results may differ materially from those projected. Forward-looking statements are based on current expectations, estimates and assumptions that involve a number of risks and uncertainties that could cause actual results to differ materially from those projected. These risks include, without limitation, our customers’ ability to meet their drilling 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 gas gathering and processing services, the Partnership’s ability to successfully implement its business plan, the Partnership’s 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, and other risks inherent in the Partnership’s business, including those described under “Risk Factors” and “Forward-Looking Statements” in the Partnership's most recent Annual Report on Form 10-K and in other reports on we file with the Securities and Exchange Commission (SEC). These reports are also available from the Partnership’s

• ffice or website, www.nblmidstream.com. Forward-looking statements are based on the estimates and opinions of management

at the time the statements are made. Noble Midstream does not assume any obligation to update forward-looking statements should circumstances, management’s estimates, or opinions change. This presentation also contains certain non-GAAP measures of financial performance that management believes are good tools for internal use and the investment community in evaluating Noble Midstream’s overall financial performance. Please see slides 25 and 26 for reconciliations of the non-GAAP financial measures used in this presentation to the most directly comparable GAAP financial measures.

2

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▪ In-line or Exceeded Guidance Across All Categories ▪ Net Income and Net Adjusted EBITDA¹, 3 above guidance ▪ Delivered Strong Throughput Growth Across All Segments ▪ Combined oil, gas and produced water gathering and sales volume up 25% from 2Q18 ▪ Fresh water delivery volumes up 22% sequentially ▪ Capital Focused on Efficient Well Connects, With Major Projects Complete ▪ 3Q18 net capital down 44% from 2Q18 ▪ Continued Peer-leading Distribution Growth/Coverage and Financial Strength ▪ 20% DPU increase over 3Q17, 2.1x Distribution Coverage Ratio¹, 2.3x Annualized Leverage Ratio² ▪ Incremental Commercial and Business Development Success

▪ Additional progress towards goal of 50% net EBITDA¹ contribution from the Permian

Basin by the end of 2020

3Q18 Highlights

1. Figures are Non-GAAP; see definition in Appendix hereto 2. Figures are Non-GAAP; Annualized leverage defined as 3Q Debt / (3Q EBITDA * 4) $549 million /( $59 million *4) 3. Net Adjusted EBITDA is Adjusted EBITDA attributable to the Partnership

3

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Actuals 3Q Guidance 3Q v 2Q 1Q18¹ 2Q18 3Q18 Gross Volumes Oil Gathered (MBbl/d)² 135 158 183 165 - 180 16% Gas Gathered (MMcf/d) 191 206 249 210 - 230 21% MBoe/d² 167 192 225 210 - 218 17% PW Gathered (MBw/d) 47 86 122 100 - 115 41% FW Delivered (MBw/d) 168 160 195 190 - 230 22% Financials ($MM) Net Income ($MM) 39 44 49 43

• 47

11% Gross Adjusted EBITDA ($MM)³ 58 64 71 65

• 70

11% Net Adjusted EBITDA ($MM) 3,4 54 49 59 55

• 59

20% DCF ($MM) ³ 47 40 49 46

• 50

23% Distribution Coverage Ratio³ 2.3x 1.8x 2.1x 1.9x - 2.1x Gross Capex ($MM) ⁵ 249 155 79 71

• 80

Net Capex ($MM) ⁵ 128 71 40 40

• 50

Third Quarter 2018 Results

4

In-line or exceeding guidance across all categories

1. Black Diamond Gathering contribution included for period following January 31, 2018 close 2. Includes crude oil sales volumes 3. Figures are Non-GAAP, see definition provided in appendix hereto 4. “Net Adjusted EBITDA” is Adjusted EBITDA attributable to the partnership 5. Excludes acquisition capital

✓ ✓ ✓ ✓ ✓ ✓ ✓ ✓ ✓ ✓ ✓ ✓

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Robust Fundamentals Across Both Delaware and DJ Basins

5

DJ Basin Highlights Delaware Basin Highlights

• Oil, Gas and Produced Water Gathering and Sales

Throughput Increased 11% Over 2Q

▪

Additional activity timed with start-up of basin incremental processing and gas offload capacity

• Significant Contribution from Mustang IDP Oil, Gas and

Produced Water Gathering at Green River DevCo

• Strong Growth at Black Diamond Gathering

▪

3Q18 throughput up 23% over 2Q18 and 29% from time of acquisition close

12 39 45 87 135 20 40 60 80 100 120 140 3Q17 4Q17 1Q18 2Q18 3Q18

Delaware Basin Oil, Gas and Water Gathering and Sales Throughput* (MBoew/d)

+18% +92% +55% +210% 110 132 167 191 212 100 120 140 160 180 200 220 3Q17 4Q17 1Q18 2Q18 3Q18

DJ Basin Oil, Gas and Water Gathering and Sales Throughput (MBoew/d)

+21% +26% +15% +11%

• Oil, Gas and Produced Water Gathering Throughput

Increased 55% Over 2Q

▪

Connected initial third-party well for infield oil, gas, & water gathering (~13,000 dedicated acres)

• LOI with Salt Creek Midstream, LLC (SCM) for 50/50

Joint Development of Delaware Basin Crude Oil Gathering and Transportation System

▪

Enhances customer market optionality with route to Wink

• Advantage Pipeline Capacity Expansion to 200 MBbl/d

from 150 MBbl/d Completed in July

▪

Long-term contract to service facilities for a major producer with ~20,000 acres in Delaware Basin

* Note: Excludes Advantage Pipeline Throughput

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Peer-Leading Distribution Coverage1 Continues

3Q 2018 NBLX Net Adjusted EBITDA and Distribution Coverage 1,2

1. Figures are Non-GAAP; see definition in Appendix hereto 2. G&A allocated to gathering and freshwater delivery based on proportionate share of adjusted EBITDA; coverage figures reflect full net maintenance capital totals 3. Assumes 20% distribution growth target

6

▪

Gathering Segment Alone Provides Ample Distribution Coverage¹

▪

1.4x Distribution Coverage Ratio¹ excluding Fresh Water

▪

Gathering Segment Represented Approximately 75% of 3Q18 Net Adjusted EBITDA¹

▪

Full-Year 2018 Guidance: 20% Distribution Growth with Distribution Coverage Ratio1 of 2.0x – 2.1x

Conservative distribution policy supported by solid gathering segment contribution

2.1x 2.0x - 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 FY2017 FY2018

Distribution Coverage Ratio1,3 & DPU

44 59 Gathering Adjusted EBITDA Column1 Total Adjusted EBITDA

Gathering EBITDA Total Adjusted EBITDA Implied Distribution Coverage of 3Q Distribution x

2.1x 1.4x $ in millions

Fresh Water Delivery EBITDA

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▪ 4Q18E Net Income of $52-$57 MM ▪ Anticipate Oil and Gas Gathering Gross Throughput Growth in 4Q18E Over 3Q18 Driven by Green River and Laramie River DevCos ▪ Expect Flat to Modest Growth in Produced Water Gathering Across DevCos in 4Q18E Over 3Q18 ▪ Fresh Water Delivery Volumes Anticipated to Increase 3% Sequentially at Guidance Midpoint ▪ 4 crews running on dedicated acreage in 4Q18E versus 5 in 3Q18

Fourth Quarter 2018 Guidance

7

168 160 180-220 1Q18 2Q18 3Q18 4Q18E

Gross Fresh Water Delivery (MBw/d)

47 86 122 130-145 1Q18 2Q18 3Q18 4Q18E

Gross Produced Water Gathering (MBw/d)

167 192 225 241-259 50 100 150 200 250 300 1Q18 2Q18 3Q18 4Q18E

Gross Oil and Gas Gathering and Sales² (MBoe/d)

54 49 59 57-62 40 42 44 46 48 50 52 54 56 58 60 1Q18 2Q18 3Q18 4Q18E

Net Adjusted EBITDA¹ ($MM)

1. Figures are Non-GAAP; see definition in Appendix hereto 2. Includes crude oil sales

195

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Updated 2018 Capital Budget Detail

8

Colorado River 2% Laramie River² 24% Green River 17% Other 1% Blanco River 51% Trinity River 5%

Gross Capital1 $538 - 550 MM

1. Excludes acquisition capital 2. Includes Black Diamond Gathering capital

Colorado River 4% Laramie River² 34% Green River 9%

Other, 0%

Blanco River 41% Trinity River 11%

Net Capital1

(attributable to the Partnership)

$270- 275 MM

▪ 3Q18 Gross Capital at High-end While Net Capital at Low-end of Guidance

▪ Higher Blanco River and Green River infrastructure capital

▪ Lowered High-end of 2018E Net Capital Guidance by 4% ▪ Capital Focused on Efficient Well Connects

128 71 40 31-36

• 10

10 30 50 70 90 110 130

1Q18 2Q18 3Q18 4Q18E

Material Decline in 2H18E Net Capital Requirements ($MM)

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Healthy Fresh Water Segment Complements Core Gathering Business

▪ Record Fresh Water Delivery Volumes in 3Q18 Reflect Delivery to 5 Completion Crews

▪ Sponsor resumed completions at Wells Ranch (Colorado River, 100% owned) and continued activity in

Mustang (Green River, 25% owned)

▪ Two completion crews operated on third-party acreage during the quarter ▪ 3Q18 fresh water volumes negatively impacted by ~15 MBw/d due to a release of a pad; however,

customer reimbursement for lost volumes reflected in 3Q18 revenue and Adjusted EBITDA

▪ Fresh Water Net Adjusted EBITDA¹ Decline Somewhat Offset by Gathering Net Adjusted EBITDA¹

Growth in 4Q18E Compared to 3Q18

▪ Delivery to 4 completion crews in 4Q18 compared to 5 crews during 3Q18 ▪ NBL completion activity heavily weighted to the Mustang Development (Green River, 25% owned)

0% 10% 20% 30% 40% 50% 60% 70% 80% 50 100 150 200 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 3Q18 Gross MBw/d % Green River & San Juan River (25% owned by NBLX)

Check with

Gross Fresh Water Delivery Volumes and Mix

1. Figures are Non-GAAP; see definition in Appendix hereto

9

Quarterly fluctuations in activity and DevCo mix

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▪ Throughput Inflection With 5 CGFs Online ▪ Oil and gas gathering volumes up >60%

• ver 2Q18

▪ Produced water volumes up 50% over

2Q18

▪ Strong Average CGF Availability of ~98.4% During

3Q18

▪ Gathering Substantially All New Delaware Basin

Wells for NBL

▪ NBL Temporarily Reducing Completion Activity in

4Q18

▪ Anticipate ~10 -15 wells to come online in

4Q18

▪ Additional completion activity expected

early in 2019

▪ First Well Online for Third-party Customer on

~13,000 Acres in the Southern Delaware ▪ Includes crude oil, gas and produced water gathering ▪ Additional activity on dedicated acres anticipated in 2019

Delaware Basin: Blanco River

Blanco River Activity 2Q18 3Q18 Oil & Gas Gathered (MBoe/d) 28 45 PW Gathered (MBw/d) 60 90 Gross Organic Capital ($MM) 92 23 Net Organic Capital ($MM) 37 9 Well Connections 26 19 Average Lateral Length (ft) ~9,100 ~8,000

Backbone infrastructure complete

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Delaware Basin: Trinity River

11

▪ 3Q18 Advantage Throughput up ~3x from Acquisition Closing Date ▪ October Throughput of ~120 MBbl/d ▪ Completed Capacity Expansion from 150 MBbl/d to 200 MBbl/d ▪ Positioned for growth in 2019 and beyond

▪

Finalized New Long-term Dedication to Service Facilities for Major Producer with ~20k Southern Delaware Acres

▪

Leverages existing asset footprint; minimal capital required

▪

Contribution to throughput anticipated in 4Q18

▪

Capital Expenditure Credit During 4Q18 Reflects Move of Two Compressor Units to Inventory for Future Buildout

30 60 88 105 106 115-125 20 40 60 80 100 120 140 Apr-17 4Q17 1Q18 2Q18 3Q18 4Q18E

Advantage Pipeline Oil Throughput (MBbl/d) Trinity River Activity 2Q18 3Q18 Gross Organic Capital ($MM) 3

• 4

Net Organic Capital ($MM) 3

• 4

Advantage Throughput* (MBbl/d) 105 106

*Excluded from total throughput due to accounting treatment as investment income

Outperforming Advantage Pipeline acquisition case

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DJ Basin: Green River

12

▪ Substantial Gathering Volume Growth During the Quarter ▪ Exit 3Q18 oil and gas gathering throughput at over 20

MBoe/d

▪ Oil, Gas and Produced Water Gathering for ~30 New Wells

Online Late 2Q18 and 3Q18

▪ Continued well production ramp anticipated into 4Q18 ▪ Diversified Gas Outlets with Delivery to 3 Processing

Providers by the End of 4Q18

▪ Fresh Water Volumes Reflect NBL’s Balanced Completion

Program Between Wells Ranch (Colorado River) and Mustang (Green River) During 3Q18

▪ Fresh Water Infrastructure for Row 2 Development

Completed During the Quarter

▪ Mustang Area: 75,000 Contiguous Net Acres Support

Significant Long-term Throughput Growth

▪ Robust full-field midstream project economics: 5-6x

• rganic build multiple on conservative 1 rig, 1

completion crew program

Mustang Infrastructure Design

Green River Activity 2Q18 3Q18 Oil & Gas Gathered (MBoe/d) n/a* 7 PW Gathered (MBw/d) n/a* 8 FW Delivered (MBw/d) 112 50 Gross Organic Capital ($MM) 29 16 Net Organic Capital ($MM) 7 4 Well Connections 5 25 Average Lateral Length (ft) ~9,900 ~10,900

*Gathering throughput commenced late in the quarter

Gathering for NBL’s row development at Mustang well underway

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DJ Basin: Laramie River

13

▪ Third-party DJ Basin 3Q18 Activity Timed with New 200 MMcf/d Basin Gas Processing Plant ▪ Conservative assumptions around line pressure relief ▪ Additional longer-term expansions provide further confidence in customer volume growth ▪ Oil Gathering Throughput on Wholly Owned Third-party System up 8% compared to 2Q18 ▪ 2nd frac crew added by customer in June ▪ Continue to Expect Black Diamond 2018 Exit Volumes Higher than Acquisition Case at 80-90 MBbl/d (75 MBbl/d in Acquisition Case) ▪ Quarterly volumes of 71 MBbl/d ▪ October throughput of >80 MBbl/d

Solid third-party throughput growth

Laramie River Activity 2Q18 3Q18 Oil & Gas Gathered (MBoe/d)¹ 71 85 PW Gathered (MBw/d) 6 9 FW Delivered (MBw/d) 46 74² Gross Organic Capital ($MM) 30 37 Net Organic Capital ($MM) 23 26 Well Connections 103 70 Average Lateral Length (ft) ~6,700 ~9,400

1. Includes crude oil sales volumes 2. 3Q18 FW volumes negatively impacted by ~15 MBw/d due to a release of a pad; however, customer reimbursement for lost volumes reflected in 3Q18 revenue and adjusted EBITDA

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DJ Basin: Colorado River

14

▪ Decline in Oil and Gas Gathering

Volumes Reflects Zero Well Connections During the Quarter

▪ ~25 Wells Planned to Come Online in

4Q18 in Wells Ranch for Oil, Gas and Water Gathering

▪ 3Q18 Fresh Water Delivery Volumes

• f 72 MBw/d Reflect Resumption of

Wells Ranch Completions

▪ Reduced Fresh Water Delivery

Activity Expected in 4Q18

Significant free cash generation

Colorado River Activity 2Q18 3Q18 Oil & Gas Gathered (MBoe/d) 93 88 PW Gathered (MBw/d) 21 15 FW Delivered (MBw/d) 1.1 72 Gross Organic Capital ($MM) 5 Net Organic Capital ($MM) 5 Well Connections 11 Average Lateral Length (ft) ~8,700 NM

Wells Ranch Infrastructure

1. Figures are Non-GAAP; see definition in Appendix hereto

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Enhancing Noble Midstream’s Permian Opportunities

15

Entity

Infield In-Basin Transportation Long-haul / Fractionation

Service Offerings Customer Mix Ownership Blanco River Trinity River

• Crude gathering
• Gas gathering
• Produced water

gathering

• Central facilities

Gas Compression

Acreage Dedicated

NBL Third Party

Acreage Dedicated

NBL 40% NBLX 60% NBL 100% NBLX Trinity River SCM JV Advantage Pipeline Crude Transportation (Reeves to Crane, Midland) Crude Gathering and Transportation (Pecos, Reeves to Wink)

Customer Count

NBL Third Party 50% NBLX 50% PAA 50% NBLX 50% SCM (LOI)¹ EPIC Crude EPIC Y-Grade

• Crude Long-Haul

(Permian to Corpus Christi)

• Marine storage
• NGL Long-haul

(Permian to Corpus Christi)

• Fractionation
• Purity product

transport

MDQ Capacity

NBL Third Party 30% NBL (Option)² 15% NBLX (Option)²

Acreage Dedicated

NBL Third Party

Recent Opportunity Addition

Acreage Dedicated

NBL Third Party

1. Closing anticipated in 4Q18 2. Option expires February 2019

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Strategic Delaware Basin Partnership Opportunity with Salt Creek

16

730 Miles of

Pipe ▪ Signed a Letter of Intent with Salt Creek to Form a 50/50 Partnership on a Delaware Crude Oil Pipeline and Gathering System ▪ Closing anticipated in 4Q18 ▪ Strategically Located Asset Would Expand Oil Infield and Intermediate Crude Gathering and Transmission Footprint in Delaware Basin ▪ NBLX’s 50% Net Capital Investment Anticipated to Total $60-$80 Million over Five Years ▪ ~75-80% of net capital funded by year-end 2019E ▪ Economics Supported By Acreage Dedications and Production Ramp From 6 Customers (Including NBL): ▪ Existing dedications totaling ~180,000 acres ▪ Line of sight to additional dedications totaling ~100,000 acres ▪ Peak Build Adjusted EBITDA² Multiple of ~3.5x to 4.5x

NewCo Crude Transportation JV

• ~180,000 contributed acres
• 6 existing customers
• 2019E rig activity: 8-10

100%

Dedication of Southern Portion of Reeves County Acreage Jointly Develop 20” Wink Trunk Line Crude Gathering and Transportation Dedications Trinity River DevCo LLC

50% 50%

Proposed Joint Venture Structure¹ Agreement Summary

1. Simplified organizational structure 2. Figures are Non-GAAP; see definition in Appendix hereto

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Expanding Delaware Basin Footprint with JV System

17

730 Miles of

Pipe ▪ SCM Commenced Construction on Newbuild Pipeline with Targeted 2Q19 In-service Date ▪ 95-Mile, 20 Inch Crude Oil Trunk Line ▪ 200 MBbl/d initial throughput capacity ▪ Provides “Wellhead to Water” Solution for Customers via Planned EPIC Connectivity ▪ Pipeline Originates in Pecos County, TX, Connects in Reeves County, TX, and Provides Access to Wink Hub ▪ Wink is a key origination point for all recently announced long-haul pipes, including premium Gulf Coast markets ▪ Project Scope Includes 200 MBbls of Incremental Crude Oil Storage ▪ About Salt Creek: ▪ Formed in 2017 by ARM Energy Holdings LLC and Ares Management, LP ▪ Full-service midstream provider, offering gas and crude gathering, compression, cryogenic processing and treating services

System Map System Details

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EPIC Crude (NBL) and Y-Grade Pipeline (NBLX) Opportunities

18

▪ NBL Option on Up to 30% Equity Interest Through Feb 1st 2019 ▪ 1,100 (720 Mainline)-mile Pipeline from Multiple Origination Points to Corpus Christi ▪ Upsized from 24” to 30” diameter ▪ Steel order has been placed, all major pumps and equipment on hand ▪ Terminals in Orla, Saragosa, Crane, Wink, Midland, Helena, and Gardendale, with export access. ▪ Base Capacity from the Permian of 600 MBbl/d (Expandable to 900 MBbl/d) ▪ Temporary Crude Service via NGL Pipeline (Crane to Corpus- Christi) Anticipated in 3Q19 ▪ Permanent service anticipated in January 2020 NBL EPIC Crude Pipeline

▪ Option Period Allows for More Construction and Commercial Progress Before Making Equity Investment ▪ Options expire February 2019 ▪ Operational and Capital Synergies from Shared Right of Way of Crude and NGL Lines

▪ NBLX Option on 15% Equity Interest Through Feb 1st 2019 ▪ ~700-mile Pipeline from Permian and Eagle Ford to Corpus Christi ▪ 24” diameter ▪ 600 MBbl/d Capacity ▪ Significant plant dedication and volumes committed from Permian processing plants ▪ Fractionation in Corpus Christi (600 MBbl/d) ▪ Future total for up to 5 potential trains ▪ Purity Product Pipelines in Corpus Christi NBLX EPIC Y-Grade Pipeline

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2018 Guidance Detail

19

Actuals Guidance Gross Volumes 1Q¹ 2Q 3Q 4Q 2018 Oil Gathered (MBbl/d)² 135 158 183 200 – 215 169 – 173 Gas Gathered (MMcf/d) 191 206 249 245 – 265 223 – 228 Oil and Gas Gathered (MBoe/d) ² 167 192 225 241 – 259 206 – 211 Produced Water Gathered (MBw/d) 47 86 122 130 – 145 97 – 100 Fresh Water Delivered (MBw/d) 168 160 195 180 – 220 176 – 186 Financials ($MM) Gross Net Income $39 $44 $49 $52 - $57 $184 - $189 Adjusted EBITDA3 $58 $64 $71 $75 - $80 $268 - $273 Capital, excluding acquisitions $249 $155 $79 $55 - $66 $538 – $550 Attributable to the Partnership Adjusted EBITDA3 $54 $49 $59 $57 – $62 $219 – $225 Distributable Cash Flow3 $47 $40 $49 $48 - $53 $184 – $190 DCF Coverage3,4 2.3x 1.8x 2.1x 1.9x – 2.1x 2.0x – 2.1x Capital, excluding acquisitions $128 $71 $40 $31 - $36 $270 – $275

1. Black Diamond Gathering contribution included for period following January 31, 2018 close 2. Includes crude oil sales volumes 3. Includes Non-GAAP measures; see definition in Appendix hereto 4. Estimates include forecasted DPU growth of 4.7% quarterly, or 20% annual

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Leading Long-Term Outlook

20

Organic – No Drop Downs

2018E 2019-2022E

Distribution per Unit 20% 20% Coverage (in all years) (1) 2.0 – 2.1x > 1.3x Year-End Annualized Leverage(1) Goals <2.8x 2019: <2.75 2020: <2.25 2021+: <2.0x ROACE (1, 3) > 15% 13 – 16% DCF Funding % of Capex and Distributions (4) ~50% ~90% (cumulative)

1. Figures are Non-GAAP, see definition provided in appendix hereto 2. Reflects combined Black Diamond, Advantage, and 2017 drop-down net acquisition cost divided by net adjusted EBTIDA; definition of adjusted EBITDA provided in appendix 3. Return on average capital employed: earnings before interest and taxes divided by (average total assets – average current liabilities); see definition provided in appendix 4. % of distributions + capex funded by distributable cash flow

Substantial organic growth with upside potential

Material Upside to Outlook

▪ Prudent Commodity Price View: Based on $50/Bbl and $3/Mcf Price Deck vs. Current Strip ▪ Continued Business Development Success, Leveraging Asset Footprints ▪ Permian Crude / Y-Grade Project and Other Long-Haul ▪ Significant and Growing Drop- Down Inventory

~90%

% of distributions + capex covered by DCF¹ 2019-2022E (cumulative) in organic base plan

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Appendix

21

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NBLX Asset Map: DJ Basin

22

Black Diamond (54.4%) Dedicated Acres: 158k Laramie River DevCo (100%)

• Oil Gathering

Area: East Pony Dedicated Acres: 44k Colorado River DevCo (100%)

• Oil Gathering

San Juan River DevCo (25%)

• FW Delivery

Area: Mustang Dedicated Acres: 75k Green River DevCo (25%)

• Oil Gathering
• Gas Gathering
• PW Gathering
• FW Delivery

Area: Wells Ranch Dedicated Acres: 78k Colorado River DevCo (100%)

• Oil Gathering
• Gas Gathering
• PW Gathering
• FW Delivery

Area: Greeley Crescent Dedicated Acres: 65k Laramie River DevCo (100%)

• Oil Gathering
• PW Gathering
• FW Delivery

Area: Bronco Dedicated Acres: 36k Gunnison River DevCo (5%)

• Oil Gathering
• PW Gathering
• FW Delivery

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NBLX Asset Map: Delaware Basin

23

Area: Delaware Basin NBL & 3rd Party Dedicated Acres: 124k 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

Map excludes 13k 3rd-party acres dedicated for oil, gas and produced water gathering in Blanco River.

LOI For SCM JV (50%)- 4Q18E Closing NBL & 3rd Party Dedicated Acres: ~180k Trinity River DevCo (100%)

• Oil Gathering and Transmission

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50%

NBLX Structure

24

Green River San Juan River Gunnison River Colorado River Laramie River Trinity River Blanco River Controlling Interest Noble Midstream Services, LLC Public Unitholders (LP) White Cliffs Pipeline L.L.C. ROFR/Wholly Owned Assets:

• East Pony Gas Gathering
• East Pony Gas Processing
• Eagle Ford Shale Midstream
• Additional DJ Acreage
• Additional Delaware Basin Services
• EPIC Crude Option¹

Noble Energy NYSE: NBL Noble Midstream Partners LP NYSE: NBLX Noble Midstream GP LLC 45.5% Limited Partner Interest 100% 100% 100% 100% 5% 25% 25% 40% 75% 95% 3.33% Non-Operating Membership Interest 54.5% Limited Partner Interest 100% Non-Economic General Partner Interest Advantage JV 60% 75% Black Diamond Non-Controlling Interest 54.4% EPIC Y- Grade Option¹ SCM JV² (LOI)

1. Option expires February 2019 2. Closing anticipated in 4Q18

50%

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Non-GAAP Financial Measures

25 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

• perating 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

• r 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

26

2016 2017 2018 $ in millions 4Q 1Q 2Q 3Q 4Q FY 1Q 2Q 3Q 4QE FYE Net Income $ 35 $ 35 $ 39 $ 44 $ 46 $ 164 39 44 49 52 - 57 184 - 189 Add: Depreciation and Amortization 2 2 2 4 4 13 11 16 18 19 65 Add: Interest Expense, Net of Amount Capitalized 0.3 1 1 1 1 2 4 4 10 Add: Income Tax Provision

• (0)

Add: Unit-Based Compensation 1 2 Add: Transaction Expenses 6 1 8 EBITDA $ 38 $ 37 $ 42 $ 48 $ 52 $ 179 58 64 71 75- 80 268 - 273 Less: EBITDA Attributable to Noncontrolling Interests 11 11 8 2 3 24 4 16 12 18 49 EBITDA Attributable to NBLX $ 27 $ 26 $ 34 $ 46 $ 48 $ 155 54 49 59 57 - 62 219 -225 Less: Maintenance Capital Expenditures & Cash Interest 2 3 4 5 5 17 7 9 10 9 - 9.5 35 DCF Attributable to NBLX $ 25 $ 24 $ 30 $ 41 $ 43 $ 138 47 40 49 48 - 53 184 - 190 Distribution Coverage 2.0x 1.8x 1.9x 2.4x 2.2x 2.1x 2.3x 1.8x 2.1x 1.9x - 2.1x 2.0x - 2.1x

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