201206 Concho Investor Presentation

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June Investor Presentation

June 2012



Forward-Looking Statements

This presentation contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Act of1934. All statements, other than statements of historical facts, included in this presentation that address activities, events or developments that the Company

expects, believes or anticipates will or may occur in the future, including, among others, statements and projections regarding the completion of the Three Riversacquisition and the Company’s future financial position, operations, performance, business strategy,capital expenditures, returns, budgets, reserves, levels ofproduction and costs and statements regarding the plans and objectives of the Company’s management for futureoperations, are forward-looking statements.The words “believe,” “expect,” “anticipate,” “plan,” “intend,” “estimate,” “potential,” “should,” “would,” “could,” or othersimilar expressions are intended toidentify forward-looking statements, which generally are not historical in nature. However, the absence of these words does not mean that the statements are notforward-looking. Without limiting the generality of the foregoing, these statements are based on certain assumptions made by the Company based onmanagement’s experience, expectations and perception of historical trends, current conditions, anticipated future developments and other factors believed to beappropriate. Forward-looking statements are not guarantees of performance. Actual results may differ materially from those implied or expressed by the forward-looking statements. Although the Company believes the expectations reflected in its forward-looking statements are reasonable and are based on reasonableassumptions, 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 tohave been correct. Moreover, such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of theCompany, which may cause actual results to differ materially from those implied or expressed by the forward-looking st atements. These include the factorsdiscussed or referenced in the “Risk Factors” section of the Company’s Form 10-K and Form 10-Q’s filed with the Securities and Exchange Commission (“SEC”)

and risks relating to declines in the prices we receive for our oil and natural gas, including natural gas liquids; uncertainties about the estimat ed quantities of oiland natural gas reserves; the effects of government regulation, permitting and other legal requirements, including new legislation or regulation of hydraulicfracturing; risks related to new federal oversight or regulation of over-the-counter derivatives; risks related to the elimination of certain federal income taxdeductions currently available to oil and natural gas exploration activities; drilling and operat ing risks; the adequacy of our capital resources and liquidity,including access to additional borrowing capacity under our credit facility; difficult and adverse conditions in the domesticand global capital and credit markets;risks related to the concentration of our operations in the Permian Basin of Southeast New Mexico and West Texas; potential financial losses or earningsreductions from our commodity price risk management program; shortages of oilfield equipment, services and qualified personnel and increased costs for suchequipment, services and personnel; risks and liabilities associated with acquired properties or businesses; uncertainties about our ability to successfully executeour business and financial plans and strategies; uncertainties about our ability to replace reserves and economically developour current reserves; generaleconomic and business conditions, either internationally or domestically or in the jurisdictions in which we operate; competition in the oil and natural gasindustry; uncertainty concerning our assumed or possible future results of operations; our substantial existing indebtedness and other important factors thatcould cause actual results to differ materially from those projected.

Accordingly, you should not place undue reliance on any of the Company’s forward-looking statements. All forward-looking statements speak only as of the dateon which such statements are made and the Company undertakes no obligation to correct or update any forward-looking statement , whether as a result of newinformation, future events or otherwise, except as required by applicable law.

This presentation includes financial measures t hat are not in accordance with generally accepted accounting principals (“GAAP”)including EBITDAX, adjustednet income, and cash margin. While management believes that such measures are useful for investors, they should not be used as a replacementfor financialmeasures that are in accordance with GAAP. For a reconciliation of each to the nearest comparable measure in accordance withGAAP, please see the Appendix.

2



Cautionary Statement Regarding Oil and Gas Quantities

The SEC requires oil and gas companies, in their filings with the SEC, to disclose proved reserves, which are those quantities of oil and gas, which, by analysis ofgeoscience 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 whetherdeterministic or probabilistic methods are used for the estimation. The SEC also permits the disclosure of separate estimatesof probable or possible reserves thatmeet SEC definitions for such reserves; however, we currently do not disclose probable or possible reserves in our SEC filings.

In this presentation, proved reserves attributable to the Company at December 31, 2011 are estimated utilizing SEC reserve recognition standards and pricingassumptions based on the trailing 12-month average first-day-of-the-month prices of $92.71 per Bbl of oil and $4.12 per MMBtu of natural gas. The Company'sestimate of its total proved reserves at December 31, 2011 is based on reports provided by Cawley, Gillespie & Associates, Inc. and Netherland, Sewell & Associates,Inc., independent petroleum engineers.

Proved reserves estimated for the 1Q12 Midland Basin acquisition at November 1 , 2011 are internal est imates based on a price of $85.00 per Bbl of oil and $4.00per MMBtu of natural gas held flat over the life of the reserves, and are not determined in accordance with SEC rules. Accordingly, proved reserves actually

booked for the PDC acquisition in the Company’s SEC filings may be lower than the internal estimates included in this presentation.

Proved reserves estimated for the Three Rivers acquisition at April 1, 2012 are internal estimates based on a price of $98.20per Bbl of oil and $4.24 per MMBtu ofnatural gas held flat over the life of the reserves, and are not determined in accordance with SEC rules. Accordingly, proved reserves actually booked for the ThreeRivers acquisition in the Company’s SEC filings may be lower than the internal estimates included in this presentation.

We may use the terms “unproved reserves,” “EUR” per well and “upside potential” to describe estimates of potentially recovera ble hydrocarbons that the SECrules prohibit from being included in filings with the SEC. These are the Company’s internal estimates of hydrocarbon quantities that may be potentiallydiscovered through exploratory drilling or recovered with additional drilling or recovery techniques. These quantities may not constitute “reserves” within themeaning of the Society of Petroleum Engineer’s Petroleum Resource Management System or SEC rules and do not include any proved reserves. EUR estimatesand drilling locations have not been risked by Company management. Actual locations drilled and quantities that may be ultimately recovered from theCompany’s interests could differ substantially. There is no commitment by the Company to drill all of the drilling locations which have been attributed to thesequantities. Factors affecting ultimate recovery include the scope of our ongoing drilling program, which will be directly affected by the availability of capital,drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, transportation constraints, regulatory approvalsand other factors; and actual drilling results, including geological and mechanical factors affecting recovery rates. Estimates of unproved reserves, per well EURand upside potential may change significantly as development of the Company’s oil and gas assets provide additional data.

Our production forecasts and expectations for future periods 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.

3



1 As of 12/31/11 at SEC pricing, adjusted to include 13 MMBoe of estimated proved reserves associated with 1Q12 Midland Basin acquisition. Does not include 58 MMBoe of estimated provedreserves associated with the pending Three Rivers acquisition.

2 For an explanation of how we calculate and use EBITDAX and adjusted net income and for a reconciliation of net income to EBITDAX and adjusted net income, please see the Appendix.3 As of 12/31/11, adjusted to include effect of 1Q12 Midland Basin acquisition. Does not include effect of pending Three Rivers acquisition.

Concho Resources Inc.

4

• Leading pure-play Permian Basinoperator

• 400 MMBoe year-end 2011 estimatedproved reserves1

• Results in 1Q 2012:

– Drilled 210 gross wells

–

Produced 6.9 MMBoe (+36% over 1Q2011)

– EBITDAX2 of $362 MM (+40% over 1Q

2011)

– Adjusted net income2 (non-GAAP) of$109 MM (+34% over 1Q 2011)

• 979,026 gross (543,509 net) acres3

•

9,275 drilling locations3

• Recently announced $1.0 Bn acquisitionof assets from Three Rivers OperatingCompany (“Three Rivers” or “3ROC”)

Permian Basin

Company Highlights

Concho Acreage Three Rivers Acreage



Permian Basin Current Activity

• Technology expandingresource potential acrossthe Permian Basin

• Activity targetingunconventional reservoirs

•

Approximately 494 rigscurrently operating

– >130 horizontal

• Increased activity driven by the emergence of newoil and liquids-rich plays

• Concho is uniquelypositioned in the Permian with exposure to some ofthe most impactful existingand emerging plays

Industry Rigs

Delaware Avalon ShaleBone Spring Wolfbone WolfcampPenn Shale

5

YesoLower Abo

Wolffork Wolfcamp

Wolfberry WolfcampCline/Penn

Mississipian

Source: PI Dwights, BHI. Concho Acreage Three Rivers Acreage



Operational Strategy

•Continued focus on the Permian Basin – Exposed to some of the most prolific oil plays in the U.S.

– Capitalize on the strategic benefits of being one of the largest operators in thePermian Basin

•Committed to rate-of-return driven growth – Reinvest high-margin cash flows into projects with robust rates of return

– Achieve superior per share growth rates while staying within cash flow

•Maintain simple, strong financial position – Conservative approach to leverage

– Ample liquidity available under credit facility

–

Hedging program to provide predictable cash flows

•Pursue acquisitions that enhance existing portfolio – Focus on strategic fit and impact to NAV and rate of return

6



12.5 17.8

77.891.0

137.3

211.5

323.5

386.5

2004 2005 2006 2007 2008 2009 201 0 201 1

0.1

1.2

3.8

5.0

7.1

10.9

15.6

23.6

2004 2005 2006 2007 2008 2009 2010 2011 2012e

28.7 - 29.8

7

Track Record of Production & Reserve Growth

Proved Reserves (MMBoe) Annual Production (MMBoe)

3.9

17.9



4%5%4%4%5%4%5%7%5%

8%8%8%8%8%8%10%8%

8%

10%11%10%7%

9%9%9%11%

9%

78%76%78%80%78%78%76%74%77%

$5.07

$4.34

$4.28

$3.81

$4.18

$4.37

$4.11

$3.33

$2.44

1Q124Q113Q112Q111Q114Q103Q102Q101Q10

8

Unhedged Cash Margin1 Percentage vs. Average NYMEX Natural Gas Price ($/MMbtu)

Cash Margin

Cash G&A

Production Taxes

LOE

$66.04 $62.49 $61.68 $65.96 $70.84 $80.07 $72.01 $73.24 $73.39Realized Price ($/Boe)

Source: FactSet1 Unhedged Cash Margin represents oil & natural gas revenues, less lease operating expenses, oil and natural gas taxes, cash G&A expense (excludes stock-based compensation),

divided by production. See Unhedged Cash Margin Reconciliation in the Appendix for a reconciliation to net income (loss).

Avg. NYMEX Gas

Strong, Liquids-driven Profitability



1 IRRs based on the aggregate economics of the total identified Yeso, Wolfberry, Bone Spring sands and Avalon shale drilling locations at 12/31/2011 and current AFE’s. Wolfberry aggregate model excludes 20-acre spaced drilling locations. IRRs exclude interest, federal and state taxes and G&A and do not take into account land cost or hedges.Excludes inventory from 1Q12 Midland Basin acquisition and Three Rivers acquisition.

Inventory Rates of Return1

9

Reinvest High Margin Cash Flow into Robust ROR Projects

38%

46%

56%

66%

30%

37%

45%

54%

33%

42%

52%

63%

24%27%

30%

34%

$80/bbl; $4/mcf $90/bbl; $4/mcf $100/bbl; $4/mcf $110/bbl; $4/mcf

Yeso Wolfberry Bone Spring sands Avalon shale



New Mexico Shelf Texas PermianDelaware Basin

2012 Capital Budget: $1.5bn 2012 Drilling & Completion Budget: $1.4bn

1 As of 12/31/11 at SEC pricing, adjusted to include 13 MMBoe of estimated proved reserves associated with 1Q12 Midland Basin acquisition. Does not include 58 MMBoe ofestimated proved reserves associated with the pending Three Rivers acquisition.

2 As of 12/31/11, adjusted to include effect of 1Q12 Midland Basin acquisition and pending Three Rivers acquisition.

92%

4% 4%

Drilling & Completion

Facilities

Leasehold & G&G

Updated 2012 Capital Budget and Activity

• Average 10 rigs in 2H12

• Expect to drill ~390 wells in 2012

• 53% of proved reserves1

• 53% of production in 1Q12

• 2,755 drilling opportunities2

– 1,995 Yeso





• Activity concentrated in Wolfberryplay


– 2,151 40-acre Wolfberry

– 2,626 20-acre Wolfberry





• Activity concentrated in the BoneSpring, Avalon and Wolfcamp

• ~472,000 gross (312,000 net) acres2


10

36%

30%

34%

New Mexico Shelf

Texas Permian

Delaware Basin



Three Rivers Acquisition – Transaction Rationale

• 58 MMBoe1 of estimated proved reserves (50% oil; 55% proved developed)

• Current daily production of approximately 7.0 MBoe/d• Over 1,500 identified drilling locations within the Company’s existing core areas

• Approximately 65% of the acreage is held by production

• Material upside through multi-zone and horizontal development

11

1 As of April 1, 2012.

Fits TheConcho

AcquisitionMold

StrategicallySignificant

Larger Platform,Same Strategy

High Quality Asset Base

• Opportunity set consistent with previous acquisitions (Chase Oil, HenryPetroleum and Marbob Energy)

•

Provides Concho with greater scale and visible growth opportunities across itscore operating areas in the Permian Basin

• Expected to be immediately accretive to all key per share metrics

• Material consolidation opportunity within the proven core of the Delaware Basin

• Meaningful addition of acreage and vertical drilling locations to core MidlandBasin

•

Continued expansion into the emerging southern Midland Basin horizontal Wolfcamp and Cline shale plays

• Continued focus on oil and liquids-rich plays in the Permian Basin

• Commitment to rate-of-return driven growth

• Pursuit of acquisitions that enhance existing portfolio



Attractive Permian Basin Consolidation Acquisition

12

Concho Acreage Three Rivers Acreage

Combination Impact – Consolidated

• Represents a significant consolidationtransaction in the Permian Basin

• Drilling opportunities across all threeof Concho’s core areas

• Additional exposure to emerging oiland liquids-rich plays

Strategic Rationale Combined Permian Basin Acreage Position

CXO1 3ROC PF

Proved Reserves (MMBoe) 400 58 458

1Q12 Net Production (MBoe/d) 76.0 7.0 83.0

Gross Drilling Locations 9,275 1,561 10,836

Gross Acreage ('000s) 980 310 1,290

Net Acreage ('000s) 544 200 744

Rig Count (Current / 2H12) 37 / 36 3 / 7 40 / 43

1 As of 12/31/11, adjusted to include effect of 1Q12 Midland Basin acquisition.



13

Northern Delaware Basin – Enhancing Leading Core Position

Concho Acreage

Concho Rig

Three Rivers Acreage

Active Horizons• Avalon shale (upper a nd lower) • Bone Spring sand (1st/2nd/3rd)• Wolfcamp shale

Active Horizons• Delaware sands

• Avalon shale (upper and lower) • Bone Spring sand (1st/2nd/3rd)

Northern DB Consolidation

• Material acreage overlap in theproven northern Delaware Basin

– Increases net acreage by 23%

• Engineered locations largely assumeone zone per location targeting:

– Delaware sands

– Avalon shale

– Bone Spring sands

– Wolfcamp shale

• Meaningful upside potential throughmulti-zone development

Combination Impact – Northern DB

Three Rivers Rig

1 As of 12/31/11.

CXO1 3ROC PF

Hz Drilling Locations 1,417 377 1,794

Gross Acreage ('000s) 289 61 350

Net Acreage ('ooos) 166 39 204




Midland Basin – Meaningful Addition to “Wolfberry” Play

• Significant addition to vertical drilling inventoryacross the Midland Basin

– Increases net acreage by 42%

– Primary targets include Wolfberry and shallow Wolfcamp

• Ability to accelerate vertical development throughrobust drilling program within low-risk, high-margin oil play

•

Attractive bolt-on to existing northern MidlandBasin acreage (Terry County)

• Evaluating horizontal upside

14

Three Rivers AcreageConcho Acreage

Midland Basin Addition

Combination Impact – Midland Basin

CXO1 3ROC PF

Vertical Locations 4,585 1,141 5,726

Horizontal Locations Under Evaluation

Gross Acreage ('000s) 224 72 295

Net Acreage ('ooos) 102 43 145


1 As of 12/31/11, adjusted to include effect of 1Q12 Midland Basin acquisition.



Midland Basin – Expanding Into The Emerging Southern Midland Basin

• Continued expansion into emerging southernMidland Basin

• Acquired acreage currently being developed with vertical wells targeting shallow Wolfcamp

– Additional zones include Dean,Clearfork, Canyon, Strawn

•

Industry ramping up horizontal developmentacross the area

– Results improving

• Operators primarily targeting the Wolfcampshale

– Multiple producing zones within the Wolfcamp

• Cline shale offers multi-zone potential• No horizontal drilling activity to date on Three

Rivers acreage

– Evaluating horizontal upside

15

Three Rivers AcreageConcho Acreage

Southern Midland Basin Expansion

Three Rivers Acreage

•Gross: 39,700•Net: 29,000

Three Rivers Rig



Why Invest in Concho?

• Leading Permian producer with focused operations in three core plays – Yeso, Delaware

Basin and Wolfberry

• Large, predominately oil and liquids-rich resource base

• Significant potential for reserve and production growth from 9,275 drilling locations1

• Compelling margins due to strong price realizations and low cost structure

• Balance sheet and liquidity positioned for future growth; history of capital discipline

• Proven management team with demonstrated track record of operational excellence,

capital discipline and acquisition expertise

1 As of 12/31/11, adjusted to include effect of 1Q12 Midland Basin acquisition. Does not include effect of pending Three Rivers acquisition.

16



Appendix

17



PERIOD SERIES

DELAWAREBASIN

FORMATION

G U A D A L A U P

E

D E L A W A R E

G R O U P LAMAR BELL CANYON

CHERRY CANYON

BRUSHY CANYON

L E O N A R D UPPER AVALON SHALE

LOWER AVALON SHALE

1ST BONE SPRING

2ND BONE SPRING

3RD BONE SPRING

WOLFCAMP WOLFCAMP

PENN PENNSYLVANIAN

PERIOD SERIES

CENTRALPLATFORM FORMATION

G U A D A L A U P E

W H I T E

-

H O R S E

TANSILL

YATES7 RIVERSQUEEN

GRAYBURG

WARDSAN ANDRES

GLORIETA

L E O N A R D

YESO

PADDOCKBLINEBRY

TUBBDRINKARD

ABO

WOLFCAMP WOLFCAMPHUECO

BURSUMPENN PENNSYLVANIAN

PERIOD SERIES

MIDLANDBASIN

FORMATION

G U A D A L A U P

E

W H I T E -

H O R S E

TANSILL

YATES7 RIVERS

QUEEN

GRAYBURG

WARDSAN ANDRES

GLORIETA

L E O N A R D CLEAR FORK UPPER LEONARD

UPPER SPRABERRY

LOWER SPRABERRY

DEAN

WOLFCAMP WOLFCAMP

PENN PENNSYLVANIAN

DelawareBasin

MidlandBasin

CentralPlatform

18

Permian Basin – Base of the Wolfcamp



EBITDAX Reconciliation

19

Year Ended T hree Months Ended

December 31, March 31,

(in thousands) 2011 2012 2011

Net income ................................................................................................................................ $ 548,137 $ 31,11 7 $ 42,57 5

Exploration and abandonments ................................................................................................ 11,7 7 9 5,97 9 7 26

Depreciation, depletion and amortization ................. ................... .................... ................... ...... 428,37 7 135 ,869 90,288

Ac cr etio n of disc ount on asset retirement obligat ions . ... ... ... ... ... ... ... ... ... ... ... ... ... ... ... ... ... ... ... ... . 2,9 65 988 7 04

Impairments of long-lived assets ................... .................... ................... .................... ................ 439 - -

Non-cash stock-based compensation .................. ................... .................... ................... ............ 19,27 1 6,128 4,468

Unrealized (gain) loss on derivatives not designated as hedges ................................................. (61,504) 126,182 204,846

Loss on sale of assets, net ................. .................... ................... ................... .................... .......... 1,1 39 895 24

Interest expense ...................................................................................................................... 118,360 35,837 29,660

Income tax expense (benefit) on continuing operations ................... .................... ................... . 285,848 19,1 17 (30,469)

Discontinued operations .......................................................................................................... (79,652) - (83,306)

EBITDAX ................................................................................................................................... 1 ,275,159$ 362,112$ 259,516$

We defin e EBITDAX as net income, plu s (1 ) expl ora tion an d aban donm ent s expense, (2 ) depr ecia tion, deplet ion an d am ort izat ion expense, (3 ) ac cr eti on

expense, (4) impairments of long-lived assets, (5) non-cash stock-based compensation expense, (6) bad debt expense (7) unrealized (gain) loss on derivativ es

not designa ted as hedges, (8) loss on sale of assets, net (9) int erest expense, (10) federal an d state income tax es on continu ing operations and (11 ) similar items

listed abov e that are pr esented in discontin ued operat ions. EBITDAX is not a m easure of net income or cash flow as determ ined by GA AP.

Our EBITDAX measure provides additional information which may be used to better understand our operations. EBITDAX is one of severalm etrics that we

use as a supplemental financial measurement in the evaluation of our business and should not beconsidered as an alternative to, or more meaningful than,

net income, as an indicator of our operating performance. Certain items excluded from EBITDAX are significant components in understanding and assessing a

company’s f inancial performance, such as a company’s cost of capital and tax structure, as w el l as the historic cost of deprec iable assets, none of w hich are

componentsof EBITDAX. EBITDAX as usedby us may not be comparable tosimilarly titled measures reportedby other companies. Webelieve that EBITDAX

is a w idely fol low ed measure of operat ing performance and is one of many metrics used by our manag ement team and by other users of our consol idated

financial statements. For example, EBITDAX can be used to assess our operat ing performance and return on capital in comparison to other independent

exploration and production companieswithout regard tofinancial or capital structure, and toassess the financial performance of our assetsand our company

wi th out rega rd t o capi ta l str uctu re or h istor ica l cost basis.



Adjusted Net Income Reconciliation

20

The following provides information that the Company believes may be useful to investors who follow the practice ofsome industry analysts who adjust company earnings and cash flows from operating activities to match realizations to

production settlement months and make other adjustments to exclude certain non-cash items.

The following table provides a reconciliation of net income (GAAP) to adjusted net income (non-GAAP).

Year En ded T hree Mont hs Ended

Decem ber 31, March 31,

(in thousands, except per share amounts) 2011 2012 2011

Net incom e - as reported ........................................................................................... $ 548,1 37 $ 31 ,11 7 $ 42,57 5

Adjustm ents for c ertain n on-cash it em s:

Unrealized mark-to-market (gain) loss on commodity and interest rate derivatives .... (61,504) 126,1 82 204,846

Impairments of long-lived assets ................................................................................ 439 - -

Leasehold abandonments ........................................................................................... 5,7 35 12 0 12 6

Discontinued operations:

Gain on sale of assets ................................................................................................ (135,943) - (141,950)

Tax impact (a) .............................................................................................................. 7 3,258 (48,121 ) (24,263)

Adjusted net income ................................................................................................. 430,122$ 109,298$ 81,334$

Adjusted basic earn ings per share:

Ad justed ne t inc ome pe r share . .... .... ... .... ... .... ... .... ... .... ... .... ... .... ... .... ... .... ... .... ... .... ... . 4.1 9$ 1.06$ 0.80$

Weighte d av erage shares used in adju sted basic earnings per shar e ... .... .... .... ... .... ... ... 102,581 102,854 102,242

Adjusted dilu ted earnings per share:

Ad justed ne t inc ome pe r share . .... .... ... .... ... .... ... .... ... .... ... .... ... .... ... .... ... .... ... .... ... .... ... . 4.1 5$ 1.05$ 0.79$

Weighte d av erage shares used in adju sted diluted earnings per share . .... ... .... ... .... ... ... 103 ,65 3 103,770 103,499

(a) The tax impact is compu ted utilizing the Company's statutory effectiv e federal and state income t ax rates. The income tax rates for the ye a

ended December 31, 20 11 and three months ended March 31, 201 2 and 2011 were approximately 37 .8%, 38.1% and 38.5%, respectively.



Unhedged Cash Margin Reconciliation

21

Years E nded

December 31,

($ in thousands, except per unit data) 1Q10 2Q10 3Q10 4Q10 1Q11 2Q11 3Q11 4Q11 2011 2010 1Q12

Net income (loss) ………………………………………………………… $ 67,540 $ 1 24,1 71 $ 20,775 $ ( 8,1 1 6) $ 42,575 $ 232,1 82 $ 356,205 $ ( 82,825) $ 548,1 37 $ 204,370 $ 31 , 11 7

Exploration and abandonments ……………………………………… 1 ,109 922 3,617 4,676 726 400 3,498 7,155 11,779 10,324 5,979

Depreciation, depletion and amortization ……………………… 50,159 49,611 57,624 84,248 90,288 98,881 115,7 30 123,478 428,377 241,642 135,869

Ac cre tion o f discou nt on a sset re tirem ent o bligat ions …… 341 316 349 476 704 7 15 751 795 2,965 1,482 988

Impairments of long-lived assets …………………………………… 256 3,489 1,922 5,947 - 76 - 363 439 11,614 -

Non-cash stock-based compensation ……………………………… 2,831 2,871 3,152 4,077 4,468 4,725 4,673 5,405 19,271 12,931 6,128

(Gain) loss on derivatives not designated as hedges………… ( 15 ,5 7 3 ) ( 11 2 ,7 6 3 ) 6 6, 10 7 1 4 9, 55 4 2 33 ,1 4 2 ( 14 4, 88 2) (3 85 ,2 22 ) 3 2 0 ,3 1 2 2 3, 35 0 8 7 ,3 25 1 5 8, 09 3

Interest expense …………………………………………………………… 11,065 11,192 12,036 25,794 29,660 21 ,660 32,881 34,159 118,360 60,087 35,837

Other (income) expense, net ………………………………………… 73 304 3,521 6,41 5 352 1 ,735 2,503 ( 61 6) 3 ,974 1 0,313 1 ,268Income tax expense (benefit) ………………………………………… 3 8, 7 6 3 7 2 ,2 20 7 , 3 92 ( 3, 09 7 ) (3 0 ,4 69 ) 1 4 3, 27 0 2 21 ,1 9 9 (4 8, 15 2 ) 2 85 ,8 48 1 1 5 ,2 7 8 1 9 ,1 1 7

Discontinued operations (a) …………………………………………… 7 , 47 0 8, 22 9 7 ,0 30 (1 1, 92 7 ) (83 ,3 06 ) - - 3 ,6 54 ( 7 9, 65 2) 10 ,80 2 -Unhedged Cash Margin ………………….………………….… 164,034$ 160,562$ 183,525$ 258,047$ 288,140$ 358,762$ 352,218$ 363,728$ 1,362,848$ 766,168$ 394,396$

Production ………………………………………………………………………… 3,21 0 MBoe 3,452 MBoe 3,899 MBoe 5,002 MBoe 5,228 MBoe 5,57 3 MBoe 6,311 MBoe 6,532 MBoe 23,644 MBoe 15,564 MBoe 6,91 9 MBoe

Unhedged Cash Margin ($/Boe) ………………….……… 51.10$ 46.51$ 47.07$ 51.59$ 55.11$ 64.38$ 55.81$ 55.68$ 57.64$ 49.23$ 57.00$

Av erage price witho ut der ivat ives ($ /Boe) …… …………… ……… 66.04$ 62.49$ 61.68$ 65.96$ 70.84$ 80.07$ 72.01$ 73.24$ 73.99$ 64.13$ 73.39$

Unhedged Cash Margin (%) ………………….……………… 7 7 % 7 4% 7 6% 7 8% 7 8% 80% 7 8% 7 6% 7 8% 7 7 % 7 8%

(a) I ncludes similar items as listed abov e, including the (gain) loss on sale of assets that is presented in discontinued operations.

Unhedged cash margin per BOE (as calculated above) is presented herein, and reconciled to the generally accepted accounting principle (“GAAP”) measure of net income (loss). Management believes this presentation may be helpful to investors as it

represents the cash generated by our oil and natural gas assets that is available for reinvestment. Concho management uses this information to analyze operating trends for comparative purposes within the industry. This measure is not intended to replace

GAAP statistics but rather to provide additional information that may be helpful in evaluating trends and performance.

Historical Unhedged Cash Margin



Hedges as of June 1, 2012

22

Current Oil and Natural Gas Swaps

2012

Second

Quarter T hird Qu arter

Fourth

Quarter T otal 2013 2014 2015 2016 2017

Oil Swaps

Vo lume (Bbl ) ..... .... .... .... .... .... .... .... .... .... ... 3,9 49, 50 0 3,876,500 3,539,500 11,365,500 12,031,000 4,513,000 1,076,000 429,000 168,000

NYMEX price (Bbl) (a) .............................. 95.27$ 96.39$ 96.23$ 95.95$ 96.08$ 92.85$ 86.69$ 88.31$ 87.00$

Natural Gas Swaps Vo lume (MMBtu ) ..... .... .... .... .... .... .... .... .... . 7 5,0 00 75,000 75,000 225,000 - - - - -

NYMEX price (MMBtu) (b) ........................ 6.54$ 6.54$ 6.54$ 6.54$ - - - - -

(a) The index prices for the oil contracts are based on the NYMEX-West Texas Intermediate monthly average futures price.

(b) The index prices for the natural gas contracts are based o n the NYMEX-Henry Hub last trading day of the mo nth futures price.



Production:

Oil equivalent (MMBoe) 28.7 - 29.8

% Oil 60% - 63%

Price differentials to NYMEX:

(excluding the effects of hedging)

Oil (Bbl) 93% - 95%

Natural gas (Mcf) 140% - 160%

Operating costs and expenses:

Lease operating expense:

Direct lease operating expense ($/Boe) $7.00 - $7.50Oil & natural gas taxes (% of oil and natural gas revenue) 8.25%

G&A expense:

Cash G&A expense ($/Boe) $3.25 - $3.50

Non-cash stock based compensation ($/Boe) $0.80 - $0.90

DD&A expense ($/Boe) $18.00 - $20.00

Exploration, abandonments and G&G ($/Boe) $0.50 - $1.50

Cash interest rates:$300 million senior notes due 2017 8.625%

$600 million senior notes due 2021 7.000%



Remainder of debt LIBOR + (150 - 250 bps)

Income taxes: 38%

Percent deferred of total taxes 80% - 90%

Capital expenditures ($ in billions) $1.5

Updated 2012 Guidance (Including Three Rivers)

23

Concho 2012 Production and Operating Guidance

Documents

201206 Concho Investor Presentation