Investor Presentation...The SEC requires oil and natural gas companies, in their filings with the SEC, to disclose proved reserves, which are those quantities of oil and natural gas,

Investor Presentation

November 2019

Forward-Looking Statements and Other Disclaimers

2

These materials and the accompanying oral presentation contain “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of

1934, as amended. All statements, other than statements of historical fact, included in this presentation that address activities, events or developments that Concho Resources Inc. (the “Company” or “Concho”) expects, believes

or anticipates will or may occur in the future are forward-looking statements. The words “estimate,” “project,” “predict,” “believe,” “expect,” “anticipate,” “potential,” “could,” “may,” “enable,” “strategy,” “intend,” “foresee,”

“positioned,” “plan,” “will,” “guidance,” ”maximize,” “outlook,” “goal,” “strategy,” “target,” or other similar expressions, as well as predicted or illustrative rates of return (“ROR”), that convey the uncertainty of future events or

outcomes are intended to identify forward-looking statements, which generally are not historical in nature. However, the absence of these words does not mean that the statements are not forward-looking. These statements are

based on certain assumptions and analyses made by the Company based on management’s experience, expectations and perception of historical trends, current conditions, current plans, anticipated future developments,

expected financings and other factors believed to be appropriate. Forward-looking statements are not guarantees of performance. Although the Company believes the expectations reflected in its forward-looking statements are

reasonable and are based on reasonable assumptions, no assurance can be given that these assumptions are accurate or that any of these expectations will be achieved (in full or at all) or will prove to have been correct.

Moreover, such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company, which may cause actual results to differ materially from those implied or

expressed by the forward-looking statements. These include the risk factors and other information discussed or referenced in the Company’s most recent Annual Report on Form 10-K and other filings with the Securities and

Exchange Commission (the “SEC”). Any forward-looking statement speaks only as of the date on which such statement is made, and the Company undertakes no obligation to correct or update any forward-looking statement,

whether as a result of new information, future events or otherwise, except as required by applicable law. Information on Concho’s website, including information referenced directly herein such as the Climate Risk Report, is not

part of this presentation. These other materials are subject to additional cautionary statements regarding risks and forward looking information.

To supplement the presentation of the Company’s financial results prepared in accordance with U.S. generally accepted accounting principles (“GAAP”), this presentation contains certain financial measures that are not prepared

in accordance with GAAP, including operating cash flow before working capital changes. See the appendix for a description and reconciliation of the non-GAAP measure presented in this presentation to the most directly

comparable financial measure calculated in accordance with GAAP.

This presentation also contains the non-GAAP term free cash flow, or FCF. Free cash flow is cash flow provided by operating activities in excess of cash flow used in investing activities for additions to oil and gas properties. The

Company believes that free cash flow is useful to investors as it provides measures to compare cash provided by operating activities and exploration and development costs across periods on a consistent basis. For future

periods, the Company is unable to provide a reconciliation of free cash flow to the most comparable GAAP financial measure because the information needed to reconcile this measure is dependent on future events, many of

which are outside management's control. Additionally, estimating free cash flow to provide a meaningful reconciliation consistent with the Company's accounting policies for future periods is extremely difficult and requires a level

of precision that is unavailable for these future periods and cannot be accomplished without unreasonable effort. Forward-looking estimates of free cash flow are estimated in a manner consistent with the relevant definitions and

assumptions noted above and herein.

The SEC requires oil and natural gas companies, in their filings with the SEC, to disclose proved reserves, which are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be

estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs and under existing economic conditions (using the trailing 12-month average first-day-of-the-month prices),

operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or

probabilistic methods are used for the estimation. The SEC also permits the disclosure of separate estimates of probable or possible reserves that meet SEC definitions for such reserves; however, the Company currently does

not disclose probable or possible reserves in its SEC filings.

In this presentation, proved reserves attributable to the Company at December 31, 2018 are estimated utilizing SEC reserve recognition standards and pricing assumptions based on the trailing 12-month average first-day-of-the-

month prices of $62.04 per Bbl of oil and $3.10 per MMBtu of natural gas.

Cautionary Statement Regarding Production Forecasts and Other Matters

Concho’s production forecasts and expectations for future periods and statements regarding drilling inventory and rate-of-return (ROR) are dependent upon many assumptions, including estimates of production decline rates from

existing wells and the undertaking and outcome of future drilling activity, which may be affected by significant commodity price declines or drilling cost increases or other factors that are beyond Concho’s control.

Concho Resources

3CXO acreage as of December 31, 2018, pro forma for transactions announced to date.

TX

NM

DELAWARE

BASIN

MIDLAND

BASIN

CXO Acreage

Leadership Position in the Permian Basin

860,000 gross (570,000 net) acres

Well Positioned to Deliver Growth & Returns

Our Strategy

› Building a great team

› Investing in high-margin assets

› Generating high-quality returns

› Maintaining a strong financial position

› High-quality asset portfolio

• Sustainable, long-term growth platform in the

Midland & Delaware Basins

• Leading well productivity

› Driving cost savings and efficiencies

› Free cash flow outlook for 2020 supports

return of capital

› Commitment to financial discipline

3Q19 Summary

4

Disciplined investment &

cost management

Delivering

On

Priorities Consistent execution Highlight asset quality

Solid operational

quarter

Strong financial

performance

Strategic portfolio

management

Increasing

shareholder returns

› Production of 330

MBoepd above high

end of guidance

› ~20% well cost

reduction exceeds

4Q19 target

› Controllable cash costs

3% lower y/y

› Generated excess

cash flow

› New Mexico Shelf sale

› Accelerates value for

legacy assets &

improves cost structure

› Board authorized

initiation of $1.5bn

share repurchase

program

› Shelf sale proceeds

jumpstart repurchases

3Q19 Operational Performance

5CXO acreage as of December 31, 2018, pro forma for announced transactions. 4Q19e production guidance Pre-Shelf Sale includes a full quarter of production volumes for the New Mexico Shelf; Post-Shelf

Sale volumes based on November 1, 2019 close date and therefore include one month of production volumes for the New Mexico Shelf.

High-Quality Asset Base

CXO Acreage

3Q19 Well

Production Above High End of Guidance

185

206

3Q18 3Q19 4Q19e

287

330

Oil (MBopd) Gas

Quarterly Volumes & 4Q19 Outlook (MBoepd)

Post-Shelf

Sale

318-325

MBoepd

(64% oil)

Pre-Shelf Sale

334-341 MBoepd

Delaware

Basin

Midland

Basin

Diversified portfolio provides capital

allocation flexibility

› Federal lands represent 1/5th of

total net acreage position

› Permit ~1 year in advance of

operations

› 3Q19 total production & oil

production above high end of

guidance

› 4Q19 guidance includes expected

impact from remaining spacing

tests

• Future development plans to

prioritize wider spacing

Lower Costs Driving Excess Cash Flow

3Q19 Financial Performance

6

Controllable Cash CostsCash Expenses excl. GP&T ($ per Boe)

LOE G&A Interest

Operating cash flow before working capital changes is a non-GAAP measure. See appendix for reconciliation to GAAP measure. E&D costs incurred is the sum of exploration and

development costs incurred.

$7.46$5.81 $5.80 $6.14 $6.26

$3.21

$3.02 $2.61 $2.38 $1.86

$3.95

$3.53

$1.99 $1.49 $1.45

$14.62

$12.36

$10.40 $10.02$9.57

$9.00

2015 2016 2017 2018 3Q19 YE20 Target

Operating Cash

Flow (“OCF”)

OCF before working

capital changes

E&D costs incurred

Realized price

($/Boe)

2Q19 3Q19

$37.68 $36.74

$779 $665

$668 $706

$785 $670

Financial Highlights ($mm)

Reducing

Cash Costs

New Mexico Shelf sale

reduces LOE &

interest expense

Focus on further

reducing cash costs

› Deliver cost-efficient growth over the long term

Strategic Focus

7Free cash flow is a non-GAAP measure. See slide 2 for a definition.

3Q19 oil volumes above guidance

Capital Efficiency

Margin Expansion

Sustainable Growth

Portfolio Management

Financial Strength

Shareholder Returns

› Develop fewer wells per project on less dense

spacing & improve cycle times

› Reduce well costs

› $9/Boe YE20 controllable cash cost target

› Improve price realizations

› Sell non-core assets, accelerate value

› Exercise capital discipline, maintain strong

financial position & flexibility

› Drive sustainable free cash flow growth

› Increase shareholder returns with dividend

growth & share repurchases

Asset sale achieves leverage target

2020+ program to prioritize smaller projects

with wider spacing to maximize returns

Significantly reduced well costs in 3Q19

Controllable cash costs 3% lower y/y

Diversifying oil sales beginning 4Q19

Generated excess cash flow in 3Q19

Authorized initiation of $1.5bn share

repurchase program

Sale of legacy New Mexico Shelf assets

ProgressStrategic Focus

Improving Capital Efficiency

8

› Further optimize drilling, completion &

facilities design

› Increase use of in-basin sand & lower

sand costs

› Utilize new commercial water solutions

› Pre-set casing

› Improve wireline efficiency

› Reduce drilling days & increase stages

per day

Ongoing Plan for Further

Reducing Well Costs

$977 $1,008

$808 $791

$1,387

$1,914

$1,278

$1,118

600

800

1000

1200

1400

1600

1800

2000

FY18 1Q19 2Q19 3Q19

Delaware Basin

Midland Basin

$1,223 $1,355 $1,023 $955Total

Program

Reducing Well CostsBasin-Level DC&E Costs ($ per foot)

1,170

1,250

1,375

4Q18 3Q19 2020e

Basin-level DC&E costs are for operated activity and include drilling, completion and wellsite equipment.

Completion EfficiencyAvg. Treated Lateral Feet per Day

Achieved cost targets

Focus on continued improvement in 2020+

↓20%

3Q19 DC&E

Costs

vs. 1H19

↓28%

↓13%

-

50

100

150

200

0 30 60 90 120 150 180

-

25

50

75

100

0 30 60 90 120 150 180

Our Extensive Development Program is Outperforming Industry

9

Northern Delaware Basin Midland Basin

2018-2019 program 180-day cumulative oil production (MBo)

Industry

Avg.

Industry

Avg.

CXO

Performance

Days Days

Cumulative oil production normalized to 7,000’. Industry averages sourced from Enverus; Northern Delaware Basin industry data covers Lea & Eddy counties, NM.

Transitioning to

wider spacing

Transition to optimal

spacing further along

CXO Wider

Spacing

CXO Closer

Spacing

Optimizing Development

10

2018-2019 Project Development

Wells per Reservoir vs. Spacing

Go-Forward Plan: Prioritize Returns

Optimizing Spacing – Illustrative Example1H192018

More suitable for

low/volatile commodity

price environment

Enables resilient,

consistent

development program

Supports sustainable

oil production & FCF

growth

# Wells per Reservoir

per Mile-Wide Section

ROR

Multiple decades

of inventory at

this spacing

%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

110%

120%

130%

$-

$10

$20

$30

$40

4 6 8 10 12 16

NP

V p

er

Sec

tio

n

2H19

Dominator

# of Wells per Reservoir

Dis

tan

ce B

etw

een

Well

s

MoreLess

Clo

ser

Wid

er

2020+

Testing to

optimize

program

ROR Focus

2018-2019

$0.3

$0.8

$0.4

$1.3

2016 2017 2018 2019e

Active Portfolio Management Accelerates Value

11

Accelerates value from legacy asset

Focuses portfolio while maintaining leading

Permian resource depth

• Minimal impact to corporate base decline rate

Improves cash cost structure

• Removing higher cost vertical wells (represents

~35% of total operated wells)

Achieves debt reduction target & increases

returns to shareholders

New Mexico Shelf Asset Sale Transaction Summary

Transaction closed

$925mm purchase price (all cash consideration)

New Mexico Shelf

• ~100,000 gross (~70,000 net) acres

• ~25 MBoepd production

• ~2,500 operated wells (~35% of total

CXO operated wells)

Track Record of Portfolio ManagementAsset & Infrastructure Monetization Proceeds ($bn)

Total proceeds $2.8bn

Cash Proceeds Jumpstart Share Repurchase & Reinforce Financial Strength

12

Capital Program

Strengthen

Balance Sheet

Additional Returns

to Shareholders

Portfolio

Enhancement

Cash

Flo

w

Pri

ori

ties

Fre

e C

ash

Flo

w

Op

po

rtu

nit

ies

Achieved debt reduction

target

Additional returns as

excess cash materializes

DividendFund with cash flow from

operations

Fund with free cash to

maximize returns

Capital Allocation Framework Allocation of Asset Sale Proceeds

Sources

~60%

~40%

Uses

Share

repurchase

Board Authorizes Initiation of $1.5bn Share

Repurchase Program

› Initial share repurchase authorization

› Asset sale proceeds jumpstart repurchase;

returning ~40% of sale proceeds

Debt reduction

Achieved debt

reduction target by

paying down

revolver

Insight into Capital Planning for 2020+

13

› Plan around conservative commodity prices

› Deliver low double-digit oil production growth

› Generate FCF

<$50/Bbl

WTI

$50/Bbl

WTI

>$50/Bbl

WTI

› Generate robust FCF

› Increase capital returns to shareholders

› Financial strength provides flexibility

Capital Allocation Strategy FCF Potential Post Shelf Sale

› Run a steady program with measured rig

adds over course of the year

› 2020+ program to prioritize smaller projects

with wider spacing to maximize returns

$50/BblWTI

$60/BblWTI

~$750

~$350

2020 FCF Outlook ($mm)

FCF Outlook

Post New Mexico Shelf Sale

2020 production growth pro forma for New Mexico Shelf sale.

High-Quality Portfolio to Deliver Growth & Shareholder Returns

14

Deliver predictable,

repeatable growth &

returns

Our core portfolio

is stronger than

ever

Disciplined

investment & cost

management is a

priority

Appendix

Our Extensive Development Program Informs Optimization Strategy

16

Horizontal Wells Drilled by Zone (Gross Operated)Delaware Basin

~5,0

00’

Midland Basin

~3,0

00’

Multiple decades of inventory

Formation 2009 - 2019 Well Count 2018 - YTD19

Brushy Canyon 23 -

Avalon Shale 148 29

1st Bone Spring 22 7

2nd Bone Spring 393 32

3rd Bone Spring 180 42

Wolfcamp Sands 52 39

Wolfcamp A 320 113

Wolfcamp B 33 22

Wolfcamp C 9 5

Wolfcamp D 38 13

Total 1,218 302

Formation 2009 - 2019 Well Count 2018 - YTD19

Middle Spraberry 46 33

Jo Mill 8 8

Lower Spraberry 143 93

Wolfcamp A 123 23

Wolfcamp B 126 47

Wolfcamp C 9 6

Wolfcamp D 3 3

Total 458 213

-

50

100

150

200

250

0 30 60 90 120 150 180 Start of '19 4Q19 Target

Operational Performance – Northern Delaware Basin Wolfcamp A

17

Generating Strong Well Performance180-day Cumulative Oil Production (MBo)

Days

CXO Wider

Spacing

CXO Closer

SpacingIndustry

Avg.

2018-2019 Activity$1,390

Reducing Well CostsDC&E Costs ($ per foot)

Cumulative oil production normalized to 7,000’. Industry average sourced from Enverus; industry data covers Lea County, NM.

Northern Delaware Basin Wolfcamp A DC&E costs are for operated activity and include drilling, completion and wellsite equipment.

17%

44%

9%

30%

What’s driving the savings?

Drilling

Completion

Sand

Water

% of Reduction

Target

↓18%+(prior ↓12%+)

Our Extensive Development Program is Outperforming Industry

18

Top 100 Wells in the Permian Basin by Six Month Cumulative Oil Production

0

2

4

6

8

10

12

14

16

18

20

Well

Co

un

t

Source: IHS Enerdeq as of October 15, 2019. Permian wells with production start date January 2017 through March 2019. Peers include APA, CVX, DVN, EOG, FANG, OXY, PE, PXD, QEP, XEC and XOM

2017-2019 Wells Put on Production

Our Commitment to Sustainability

19

Reduce

Flaring

Expand Water

Recycling

Manage Climate

Risk

↓50%

2016-2018

Asset-Wide

Focus

Published Inaugural

Report

Available at

www.concho.com/corporate-responsibility

Source: Bernstein Research dated July 19, 2019. Peers include APA, CDEV, CVX, FANG, ECA, Endeavor, EOG, NBL, OXY, PE, PXD, WPX, XEC and XOM.

Gas Capture

PerformanceTexas Permian

Basin

% Wellhead Gas

Flared/Vented for

December 2018

20%

14%

9% 9%

6% 5% 4% 3% 3% 2% 2% 1% 1% 1% 1%

Peer1

Peer2

Peer3

Peer4

Peer5

Peer6

Peer7

Peer8

Peer9

Peer10

Peer11

Peer12

Peer13

Peer14

Operating Cash Flow Before Changes in Working CapitalNon-GAAP Reconciliation

20

The Company provides operating cash flow (“OCF”) before working capital changes, which is a non-GAAP financial measure. OCF before working capital changes represents net cash

provided by operating activities as determined under GAAP without regard to changes in operating assets and liabilities, net of acquisitions and dispositions as determined in accordance

with GAAP. The Company believes OCF before working capital changes is an accepted measure of an oil and natural gas company’s ability to generate cash used to fund development

and acquisition activities and service debt or pay dividends. This non-GAAP measure should not be considered as an alternative to, or more meaningful than, net cash provided by

operating activities as an indicator of operating performance.

The following table provides a reconciliation from the GAAP measure of net cash provided by operating activities to OCF before working capital changes:

Net cash provided by operating activities $ 665 $ 779

Changes in cash due to changes in operating assets and liabilities:

Accounts receivable 52 (144)

Prepaid costs and other 5 5

Inventory (1) (1)

Accounts payable (11) 6

Revenue payable 25 3

Other current liabilities (29) 20

Total working capital changes 41 (111)

Operating cash flow before working capital changes $ 706 $ 668

(in millions)

Three Months Ended

September 30,

Three Months Ended

June 30,

2019 2019

59

74

99

85

4Q18 Exit 1Q19 Exit 2Q19 Exit 3Q19 Exit

Activity Overview

21

Avg. Rig

Count

YTD 2019 Activity – Well Counts YTD 2019 Activity – Drilling Rigs & Frac Crews

Inventory of Wells Waiting on Completion

Gross Operated

34 33 26

Total Gross

Number of Wells

Drilled

Number of Wells

Completed

Number of Wells

Put on Production

Delaware Basin 251 186 210

Midland Basin 120 129 152

Total 371 315 362

Gross Operated

Number of Wells

Drilled

Number of Wells

Completed

Number of Wells

Put on Production

Delaware Basin 116 118 127

Midland Basin 97 107 124

Total 213 225 251

Net Operated

Number of Wells

Drilled

Number of Wells

Completed

Number of Wells

Put on Production

Delaware Basin 91 96 100

Midland Basin 78 89 103

Total 169 185 203

Avg. WI 79.3% 82.1% 80.8%

Guidance

2H19 Avg. Rig Count 18

FY19 Gross Operated Activity (# wells)

Drilling 270-290

Completing 270-290

Put on Production 330-350

19

Total 1Q19 2Q19 3Q19

Avg. Rig Count 33 26 19

Avg. Frac Crews 8 8 7

Hedge PositionUpdated as of October 29, 2019

22

1These oil derivative contracts are settled based on the New York Mercantile Exchange (“NYMEX”) – West Texas Intermediate ("WTI") calendar-month average futures price.

2These oil derivative contracts are settled based on the Brent calendar-month average futures price.

3The basis differential price is between Midland – WTI and Cushing – WTI. The majority of these contracts are settled on a calendar-month basis, while certain contracts assumed in connection with the RSP acquisition are settled on a trading-month basis.

4The natural gas derivative contracts are settled based on the NYMEX – Henry Hub last trading day futures price.

5The basis differential price is between NYMEX – Henry Hub and El Paso Permian.

6The basis differential price is between NYMEX – Henry Hub and WAHA.

2019 2021

4Q 1Q 2Q 3Q 4Q Total Total

Oil Price Swaps - WTI1:

Volume (MBbl) 13,469 12,517 11,075 10,067 9,586 43,245 17,517

Price per Bbl 56.46$ 57.01$ 56.88$ 56.93$ 57.01$ 56.96$ 54.30$

Oil Price Swaps - Brent2:

Volume (MBbl) 2,178 1,456 1,456 1,472 1,472 5,856 -

Price per Bbl 62.08$ 60.12$ 60.12$ 60.12$ 60.12$ 60.12$ -$

Oil Costless Collars1:

Volume (MBbl) 1,058 - - - - - -

Ceiling price per Bbl 62.95$ -$ -$ -$ -$ -$ -$

Floor price per Bbl 55.43$ -$ -$ -$ -$ -$ -$

Oil Basis Swaps3:

Volume (MBbl) 16,053 14,651 10,647 10,580 10,120 45,998 16,790

Price per Bbl (2.19)$ (0.46)$ (0.65)$ (0.66)$ (0.71)$ (0.60)$ 0.60$

Natural Gas Price Swaps - HH4:

Volume (BBtu) 37,750 35,024 32,313 30,038 28,498 125,873 36,500

Price per MMBtu 2.51$ 2.46$ 2.46$ 2.47$ 2.47$ 2.47$ 2.52$

Natural Gas Basis Swaps - HH/EPP5:

Volume (BBtu) 28,820 25,770 23,960 22,080 21,770 93,580 36,500

Price per MMBtu (0.76)$ (1.06)$ (1.07)$ (1.07)$ (1.07)$ (1.07)$ (0.66)$

Natural Gas Basis Swaps - HH/WAHA6:

Volume (BBtu) 9,200 7,280 7,280 7,360 7,360 29,280 10,950

Price per MMBtu (0.77)$ (1.10)$ (1.10)$ (1.10)$ (1.10)$ (1.10)$ (0.66)$

2020

2019 GuidanceUpdated as of October 29, 2019

4Q19 Guidance

• Production guidance (Post-Shelf

Sale): 318 MBoepd-325 MBoepd

› 64% oil mix

• GP&T $1.35-$1.45 per Boe

• DD&A $16.50-$16.85 per Boe

23

Note: The Company’s capital program guidance excludes acquisitions. All guidance is subject to change without notice depending upon a number of factors, including commodity prices,

industry conditions and other factors that are beyond the Company’s control.

Production

Total production growth 23% - 27%

Oil production growth 22% - 26%

Price realizations, excluding commodity derivatives

Oil differential (per Bbl) (Relative to NYMEX - WTI; excludes Midland-Cushing basis differential) ($2.00) - ($2.50)

Natural gas (per Mcf) (% of NYMEX - Henry Hub) 60% - 80%

Operating costs and expenses ($ per Boe, unless noted)

Lease operating expense and workover costs $6.00 - $6.50

Gathering, processing and transportation $0.85 - $0.95

Oil and natural gas taxes (% of oil & natural gas revenues)

General and administrative ("G&A") expense:

Cash G&A expense $2.20 - $2.40

Non-cash stock-based compensation $0.70 - $0.90

DD&A $15.75 - $16.25

Cash exploration and other $0.25 - $0.50

Interest expense ($mm):

Cash $200 - $220

Non-cash

Income tax rate (%)

Capital program ($bn) $2.8 - $3.0

2019

Guidance

7.60%

$6

22%