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Quarterly UpdateOctober 29, 2019

3Q | 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 of1934, 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, believesor 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 oroutcomes 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 arebased 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 arereasonable 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 orexpressed 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 andExchange 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 notpart 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 preparedin 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 directlycomparable 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. TheCompany 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 futureperiods, 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 ofwhich 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 levelof 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 andassumptions 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 beestimated 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 orprobabilistic 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 doesnot 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 MattersConcho’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 fromexisting 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.

3Q19 Summary

3

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

› Planned $925mm New Mexico Shelf sale

› Accelerates value for legacy assets & improves cost structure

› Board authorized initiation of $1.5bn share repurchase program

› Planned asset sale proceeds jumpstart repurchases

3Q19 Operational Performance

4CXO 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 assume an early November 2019 close date and therefore include one month of production volumes for the New Mexico Shelf.

High-Quality Asset Base

CXO Acreage3Q19 Well

Production Above High End of Guidance

185206

3Q18 3Q19 4Q19e

287

330

Oil (MBopd) Gas

Quarterly Volumes & 4Q19 Outlook (MBoepd)

Post-ShelfSale

318-325 MBoepd(64% oil)

Pre-Shelf Sale334-341 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

5

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

6Free 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 returnsSignificantly reduced well costs in 3Q19

Controllable cash costs 3% lower y/yDiversifying oil sales beginning 4Q19

Generated excess cash flow in 3Q19Authorized initiation of $1.5bn share repurchase program

Announced sale of legacy New Mexico Shelf assets for $925mm

ProgressStrategic Focus

Improving Capital Efficiency

7

› 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 targetsFocus 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

8

Northern Delaware Basin Midland Basin2018-2019 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

9

2018-2019 Project DevelopmentWells per Reservoir vs. Spacing

Go-Forward Plan: Prioritize Returns Optimizing Spacing – Illustrative Example

1H192018

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

NPV

per

Sec

tion

2H19

Dominator

# of Wells per Reservoir

Dis

tanc

e B

etw

een

Wel

ls

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

10

Accelerates value from legacy assetFocuses 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

› $925mm purchase price (all cash consideration)

› Closing anticipated November 2019

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

Planned transaction is subject to customary terms, conditions and post-closing adjustments.

Cash Proceeds Jumpstart Share Repurchase & Reinforce Financial Strength

11

Capital Program

Strengthen Balance Sheet

Additional Returns to Shareholders

Portfolio Enhancement

Cas

h Fl

ow

Prio

ritie

sFr

ee C

ash

Flow

O

ppor

tuni

ties

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 ProceedsSources

~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 reductionAchieve debt reduction target by paying down revolver

Insight into Capital Planning for 2020+

12

› Plan around conservative commodity prices› Deliver sustainable 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 Planned 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 OutlookPost New Mexico Shelf Sale

Appendix

Our Extensive Development Program Informs Optimization Strategy

14

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 - YTD19Brushy Canyon 23 -Avalon Shale 148 291st Bone Spring 22 72nd Bone Spring 393 323rd Bone Spring 180 42Wolfcamp Sands 52 39Wolfcamp A 320 113Wolfcamp B 33 22Wolfcamp C 9 5Wolfcamp D 38 13Total 1,218 302

Formation 2009 - 2019 Well Count 2018 - YTD19Middle Spraberry 46 33Jo Mill 8 8Lower Spraberry 143 93Wolfcamp A 123 23Wolfcamp B 126 47Wolfcamp C 9 6Wolfcamp D 3 3Total 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

15

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

Days

CXO Wider Spacing

CXO Closer Spacing

Industry 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

16

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

0

2

4

6

8

10

12

14

16

18

20

Wel

l Cou

nt

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

17

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

18

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 $ 779Changes in cash due to changes in operating assets and liabilities:

Accounts receivable 52 (144)Prepaid costs and other 5 5Inventory (1) (1) Accounts payable (11) 6Revenue payable 25 3Other current liabilities (29) 20

Total working capital changes 41 (111)Operating cash flow before working capital changes $ 706 $ 668

(in millions)

Three Months EndedSeptember 30,

Three Months EndedJune 30,

2019 2019

5974

9985

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

Activity Overview

19

Avg. RigCount

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

Inventory of Wells Waiting on CompletionGross Operated

34 33 26

Total GrossNumber of Wells

DrilledNumber of Wells

CompletedNumber of Wells

Put on ProductionDelaware Basin 251 186 210Midland Basin 120 129 152Total 371 315 362

Gross OperatedNumber of Wells




Net OperatedNumber of Wells




Avg. WI 79.3% 82.1% 80.8%

Guidance2H19 Avg. Rig Count 18FY19 Gross Operated Activity (# wells)

Drilling 270-290Completing 270-290Put on Production 330-350

19

Total 1Q19 2Q19 3Q19Avg. Rig Count 33 26 19Avg. Frac Crews 8 8 7

Hedge PositionUpdated as of October 29, 2019

20

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 20214Q 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

21Note: 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.

ProductionTotal 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 - $6.50Gathering, processing and transportation $0.85 - $0.95Oil and natural gas taxes (% of oil & natural gas revenues)General and administrative ("G&A") expense:

Cash G&A expense $2.20 - $2.40Non-cash stock-based compensation $0.70 - $0.90

DD&A $15.75 - $16.25Cash exploration and other $0.25 - $0.50Interest expense ($mm):

Cash $200 - $220Non-cash

Income tax rate (%)Capital program ($bn) $2.8 - $3.0

2019 Guidance

7.60%

$622%

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