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Investor Presentation SEPTEMBER 2015

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  • Investor Presentation

    SEPTEMBER 2015

  • Forward-Looking Statements and Other Disclaimers

    2

    This presentation contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical fact, included in this

    presentation that address activities, events or developments that Concho Resources Inc. (the “Company”) expects, believes or anticipates will or may occur in the future are forward-looking statements. Forward-looking statements contained in this

    presentation specifically include statements, estimates and projections regarding the Company's future financial position, operations, performance, business strategy, capital expenditure budget, liquidity and capital resources, the timing and success of

    specific projects, outcomes and effects of litigation, claims and disputes, derivative activities and potential financing. The words “estimate,” “project,” “predict,” “believe,” “expect,” “anticipate,” “potential,” “could,” “may,” “foresee,” “plan,” “goal” or other similar

    expressions 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 made by the Company based on management's experience, expectations and perception of historical trends, current conditions, anticipated future developments 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 factors discussed or referenced in the “Risk Factors” section of the Company's most recent Form 10-K filing; risks relating to declines in

    the prices the Company receives for its oil and natural gas; uncertainties about the estimated quantities of oil and natural gas reserves; drilling and operating risks, including risks related to properties where the Company does not serve as the operator and

    risks related to hydraulic fracturing activities; the adequacy of the Company’s capital resources and liquidity including, but not limited to, access to additional borrowing capacity under the Company’s credit facility; the effects of government regulation,

    permitting and other legal requirements, including new legislation or regulation of hydraulic fracturing and the export of oil and natural gas; environmental hazards, such as uncontrollable flows of oil, natural gas, brine, well fluids, toxic gas or other pollution

    into the environment, including groundwater contamination; difficult and adverse conditions in the domestic and global capital and credit markets; risks related to the concentration of the Company’s operations in the Permian Basin of southeast New Mexico

    and west Texas; disruptions to, capacity constraints in or other limitations on the pipeline systems that deliver the Company’s oil, natural gas liquids and natural gas and other processing and transportation considerations; the costs and availability of

    equipment, resources, services and personnel required to perform the Company’s drilling and operating activities; potential financial losses or earnings reductions from the Company’s commodity price management program; risks and liabilities related to the

    integration of acquired properties or businesses; uncertainties about the Company’s ability to successfully execute its business and financial plans and strategies; uncertainties about the Company’s ability to replace reserves and economically develop its

    current reserves; general economic and business conditions, either internationally or domestically; competition in the oil and natural gas industry; uncertainty concerning the Company’s assumed or possible future results of operations; and other important

    factors that could 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. 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.

    This presentation includes financial measures that are not in accordance with generally accepted accounting principles (“GAAP”), including EBITDAX. While management believes that such measures are useful for investors, they should not be used as a

    replacement for financial measures that are in accordance with GAAP. For a reconciliation of EBITDAX to the nearest comparable measure in accordance with GAAP please see the appendix.

    The Securities and Exchange Commission (“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, 2014 are estimated utilizing SEC reserve recognition standards and pricing assumptions based on the trailing 12-month average first-day-of-the-month prices of $91.48 per

    Bbl of oil and $4.35 per MMBtu of natural gas. The Company’s estimate of its total proved reserves at December 31, 2014 is based on reports prepared by Cawley, Gillespie & Associates, Inc. and Netherland, Sewell & Associates, Inc., independent

    petroleum engineers. The Company may use the terms “unproved reserves,” “resource potential,” “EUR” per well, “upside potential” and “prospective acreage” to describe estimates of potentially recoverable hydrocarbons that the SEC rules prohibit from

    being included in filings with the SEC. These are based on analogy to the Company’s existing models applied to additional acres, additional zones and tighter spacing and are the Company’s internal estimates of hydrocarbon quantities that may be

    potentially discovered through exploratory drilling or recovered with additional drilling or recovery techniques. These quantities may not constitute “reserves” within the meaning of the Society of Petroleum Engineer’s Petroleum Resource Management System

    or SEC rules. EUR estimates, resource potential and identified drilling locations have not been fully risked by Company management and are inherently more speculative than proved reserves estimates. Actual locations drilled and quantities that may be

    ultimately recovered from the Company’s interests could differ substantially. There is no commitment by the Company to drill all of the drilling locations, which have been attributed to these quantities. Factors affecting ultimate recovery include the scope of

    the Company’s 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 approvals,

    actual drilling results, including geological and mechanical factors affecting recovery rates, and other factors. Estimates of unproved reserves, resource potential, per well EUR and upside potential may change significantly as development of the Company’s

    oil and natural gas assets provide additional data. The Company’s production forecasts and expectations for future periods 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.

  • Concho Resources

    3

    Strategic acreage position in the Permian Basin

    • ~1.1 MM gross (700,000 net) acres

    • Core areas in the Delaware Basin, Midland Basin and New

    Mexico Shelf

    High-quality, long-life reserve base

    • 637.2 MMBoe estimated proved reserves

    • ~3.7 BBoe of total resource potential, including proved

    reserves

    Leading Permian operator

    • 2Q15 average daily production of ~147 MBoepd (67% oil)

    • Scale, technology and people – key advantages to delivering

    top-tier results and cost structure

    • Currently running 14 rigs

    NEW MEXICO

    TEXAS

    Acreage, proved reserves and resource potential as of December 31, 2014.

  • -

    200

    400

    600

    800

    1,000

    1,200

    1,400

    1,600

    1,800

    $0

    $20

    $40

    $60

    $80

    $100

    $120

    $140

    $160

    2007 2008 2009 2010 2011 2012 2013 2014 2015

    Oil Price ($/Bbl) U.S. Oil Rig Count

    Recent History of U.S. Oil Production, Price and Rig Count

    -0.2% -1.5% 7.1% 2.2% 3.3% 14.6% 14.9% 15.5%

    WT

    I O

    il P

    ric

    e (

    $/B

    bl)

    O

    il Rig

    Co

    un

    t

    U.S. Oil Production (YoY % Growth)

    Source: U.S. oil rig count data from Baker Hughes. U.S. Oil production annual growth from EIA.

    ’08-’09

    Downcycle

    Current

    Downcycle

    Key Observations:

    • Extreme moves in crude oil prices have occurred before

    • The industry has a history of adapting to lower prices

    • U.S. oil shale plays now represent a significant, low-cost source of supply

    4

  • How Does Concho’s Strategy Change During Extreme Oil Price Moves?

    People

    Assets

    Returns

    Balance Sheet • Maintaining financial strength is a priority

    • Disciplined hedge program to protect cash flows

    • Executing a returns-based, disciplined capital program

    • Cost structure aligning with lower commodity price environment

    • Drilling and completion optimization maximizing resource recovery and returns

    • Targeted, high-quality acreage positions in the Delaware Basin, Midland Basin and New Mexico Shelf

    • Operational efficiencies driving faster cycle times

    • Enhanced completions improving well performance across portfolio

    • Highly technical, motivated team working to delineate resource while providing scale to grow

    • Strong community ties and legacy of successful consolidation in the Permian Basin

    5

    It Doesn’t. Concho’s Strategy is Built to Withstand Price Cycles

    Four key principles underpin our strategy:

  • Intense Focus on the Permian Basin

    6 Source: Permian Basin rig count data from Baker Hughes as of September 1, 2015.

    Permian Basin

    Current HZ Rig Activity

    Unique Advantages of the

    Permian Basin

    Geographic reach (it’s big)

    Resource rich

    Multi-zone opportunities

    Repeatability

    Infrastructure

    Access to markets, local refineries

    Crude quality

    Historical industry activity

    HZ Rig

    CXO Operated HZ Rig

  • Drilling Days

    15% y/y

    Feet Drilled per Day

    18% y/y

    Lateral Length

    10% y/y

    Delivering Growth and Value in the Northern Delaware Basin

    ACREAGE POSITION

    ~365,000 gross

    (255,000 net) acres

    CURRENT RIG

    COUNT

    9 Horizontal Rigs

    Note: Acreage as of December 31, 2014. Operational performance metrics compare 2Q15 versus 2Q14.

    EDDY LEA

    CULBERSON

    LOVING

    7

    CXO ACREAGE

    CXO 2Q15 HZ WELL

    Recent Well Results

    Added 52 HZ wells with >30 days production

    data in 2Q15 (avg. lateral length 5,152’)

    • Avg. 30-day peak rate: 994 Boepd (71% oil)

    • Avg. 24-hour peak rate: 1,459 Boepd

    Operational Performance

    Drilling efficiencies compressing cycle times

    • 15% reduction in drilling days year-over-year

    • 10% increase in lateral length year-over-year

    Significant reduction in completion costs

    • 24% reduction in stimulation costs per lateral

    foot year-over-year

  • Advancing the Oil-Rich Avalon Shale

    8

    NORTHERN

    DELAWARE BASIN

    Brushy

    Canyon

    Avalon

    1st Bone

    Spring

    2nd Bone

    Spring

    3rd Bone

    Spring

    Wolfcamp

    Upper

    Avalon

    Lower

    Avalon

    ~8,700’

    Burial Depth

    (top of the U. Avalon)

    ~1,000’ Thick

    Avalon Shale • Targeting multiple benches in the Avalon Shale

    • Current spacing outlook is 4 to 6 wells per section

    • Downspacing tests planned in 2015

    Note: Acreage as of December 31, 2014.

    EDDY LEA

    CULBERSON LOVING

    CXO ACREAGE

  • Applying Enhanced Completions to the Oil-Rich Avalon Shale

    9

    1Production data normalized for a 4,300’ lateral.

    Note: Rate-of-return calculated based on $60/Bbl of oil and $3.50/Mcf of gas.

    NORTHERN

    DELAWARE BASIN Enhanced completion design unlocks oil-rich

    Avalon shale

    • Improves oil recovery

    • Improves capital efficiency

    25 to 30 wells planned for 2015

    Rate-of-Return

    70%+ for Enhanced completions

    Well Cost

    $5.5 - $6.0 MM Enhanced avg.

    Avalon Shale

    0

    20

    40

    60

    80

    100

    120

    140

    0 30 60 90 120 150 180

    Base Avg. (13 wells) Enhanced Avg. (5 wells)

    Enhanced Completions

    Well Performance

    Days

    Avg

    . C

    um

    ula

    tive

    Pro

    du

    cti

    on

    (M

    Bo

    e)1

    60%+

    Increase

  • Strong Results and Significant Inventory for Future Growth

    10 1Wells with a minimum of 30 days of production at June 30, 2015. 2Identified locations and acreage as of December 31, 2014.

    Concho’s ~365,000 gross acres are prospective for six zones

    with downspacing potential

    Brushy Canyon

    Avalon Shale

    1st Bone Spring

    2nd Bone Spring

    3rd Bone Spring

    Wolfcamp Shale

    Well

    Count1 Avg. Peak Rate (Boepd)

    30-Day (% Oil) 24-Hour

    21

    15

    73

    67

    279

    21

    620 (81%)

    526 (73%)

    668 (85%)

    939

    974

    1,076

    1,347

    1,471

    1,337

    788 (51%)

    938 (75%)

    860 (41%)

    Formation Identified

    Locations2

    700

    1,400

    1,400

    1,500

    3,200

    1,600

    Wells per

    Section

    4

    4

    4

    4 to 6

    4 to 6

    4

    Deep Inventory of Identified Horizontal Locations NORTHERN DELAWARE BASIN

  • Industry-Leading Performance in the Southern Delaware Basin

    ACREAGE POSITION

    ~275,000 gross

    (170,000 net) acres

    CURRENT RIG

    COUNT

    2 Horizontal Rigs

    PECOS

    REEVES

    WARD

    11

    CXO ACREAGE

    CXO 2Q15 HZ WELL

    Recent Well Results

    Added 12 HZ wells with >30 days production data in 2Q15

    (avg. lateral length 6,302’)

    • Avg. 30-day peak rate: 1,163 Boepd (78% oil)

    • Avg. 24-hour peak rate: 1,392 Boepd

    Drilling efficiencies compressing cycle times

    • 25% reduction in drilling days year-over-year

    • 30% increase in feet drilled per day year-over-year

    Significant reduction in completion costs

    • 33% reduction in stimulation costs per lateral foot year-

    over-year

    Drilling Days

    25% y/y

    Feet Drilled per Day

    30% y/y

    Lateral Length

    18% y/y

    Operational Performance

    Note: Acreage as of December 31, 2014. Operational performance metrics compare 2Q15 versus 2Q14.

  • Generating Efficiencies in the Midland Basin

    HORIZONTAL CORE

    ACREAGE POSITION

    ~200,000 gross

    (110,000 net) acres

    CURRENT RIG

    COUNT

    2 Horizontal Rig ECTOR

    ANDREWS

    MIDLAND

    12

    MARTIN

    CRANE UPTON

    CXO ACREAGE

    CXO 2Q15 HZ WELL

    Added 21 HZ wells with >30 days production data in

    2Q15 (avg. lateral length 5,930’)

    • Avg. 30-day peak rate: 758 Boepd (82% oil)

    • Avg. 24-hour peak rate: 996 Boepd

    Recent Well Results

    Operational Performance

    Drilling efficiencies compressing cycle times

    • 25% reduction in drilling days year-over-year

    • 40% increase in feet drilled per day year-over-year

    Significant reduction in completion costs

    • 32% reduction in stimulation costs per lateral foot year-

    over-year

    Note: Acreage as of December 31, 2014. Operational performance metrics compare 2Q15 versus 2Q14.

    Drilling Days

    25% y/y

    Feet Drilled per Day

    40% y/y

    Lateral Length

    16% y/y

  • Competitive Returns on the New Mexico Shelf

    ACREAGE POSITION

    ~160,000 gross

    (110,000 net) acres

    CURRENT RIG

    COUNT

    1 Horizontal Rig

    13

    LEA

    EDDY

    CHAVES

    CXO ACREAGE

    CXO 2Q15 HZ W ELL

    Recent Well Results

    Added 17 HZ wells with >30 days production data in

    2Q15 (avg. lateral length 4,204’)

    • Avg. 30-day peak rate: 331 Boepd (83% oil)

    • Avg. 24-hour peak rate: 477 Boepd

    Operational Performance

    Drilling more efficiently and driving down costs

    • 11% increase in feet drilled per day year-over-year

    • 12% reduction in drilling costs per lateral foot year-

    over-year

    Avg. well cost: $2.5 MM to $3.5 MM

    Feet Drilled per Day

    11% y/y

    Cost per Lateral Foot

    12% y/y for drilling costs

    Note: Acreage as of December 31, 2014. Operational performance metrics compare 2Q15 versus 2Q14.

  • 37

    30

    18

    14

    4Q14 1Q15 2Q15 Current

    Executing a Disciplined, Flexible Capital Program

    14 1Based on 2015 production guidance midpoint.

    Note: Capital program excludes unbudgeted acquisitions.

    76%

    12%

    12%

    Delaware

    Basin

    Midland

    Basin

    Rig Program Progression

    Avg. Quarterly Rig Count

    ↓23 Rigs

    since 4Q14

    New Mexico

    Shelf

    2015 Capital Program Allocation

    2015 Capital program $1.8 to $2.0 BN

    › 24% to 26% annual production growth target

    › Dynamic capital allocation

    › Significant operational flexibility to scale activity based

    on commodity price outlook

    Hedge position for 2H15 covers ~78% of expected oil

    production1 at ~$74/Bbl

    Plan to run 2016 drilling program within cash flow

  • Improving Cost Structure

    $8.15 $8.26 $7.77 $7.64 $7.30

    $5.61 $5.21 $4.06 $2.91

    $3.30

    $4.05 $3.77

    $3.63

    $3.65 $3.39

    2Q14 3Q14 4Q14 1Q15 2Q15

    $17.81 $17.24

    $15.46

    $14.20 $13.99

    LOE & WORKOVER

    ↓ 10% Lower

    Year-Over-Year

    Cash Operating Expenses ($/Boe)

    LOE & Workover Production Taxes Cash G&A

    15

    CASH G&A

    ↓ 16% Lower

    Year-Over-Year

  • Prioritizing a Strong Balance Sheet

    16

    5

    7.1

    10.9

    15.6

    23.6

    29.8

    33.6

    40.9

    0.0x

    0.5x

    1.0x

    1.5x

    2.0x

    2.5x

    3.0x

    3.5x

    4.0x

    0

    5

    10

    15

    20

    25

    30

    35

    40

    45

    2007 2008 2009 2010 2011 2012 2013 2014

    FY

    E D

    eb

    t-to-E

    BIT

    DA

    X1

    Pro

    du

    cti

    on

    (M

    MB

    oe)

    Production (MMBoe) FYE Debt-to-EBITDAX

    Avg. FYE

    Debt-to-EBITDAX1: 1.8x

    1EBITDAX is a non-GAAP measure. See slide appendix for reconciliation to GAAP measure.

    2007 – 2014

    Production

    35% CAGR

    Track Record of Measured Growth,

    Prudent Financial Management

  • Creating Value Through the Cycle

    Low-cost operator with high-quality assets and healthy financial

    position

    Exercising patience and discipline

    › Looking for commodity price stability before increasing

    activity

    › Focusing on consolidating the right assets at the right time

    and at the right price

    Improving capital productivity

    Maintaining superior positioning for growth acceleration

    Proven strategy,

    experienced team

    and high-quality

    assets to weather

    commodity price

    cycles

    17

  • Appendix

  • 2015 Operational & Financial Outlook

    3Q15 OUTLOOK

    Production:

    143 to 147 MBoepd

    Production

    Year-over-year growth 24% - 26%

    Oil mix 64% - 66%

    Price realizations, excluding commodity derivatives (% of NYMEX)

    Crude oil (per Bbl) 90% - 93%

    Natural gas (per Mcf) 90% - 100%

    Operating costs and expenses ($/Boe, unless otherwise noted)

    LOE

    Direct LOE $7.50 - $8.00

    Oil & gas taxes (% of oil & gas revenues) 8.25%

    G&A

    Cash G&A $3.40 - $3.90

    Non-cash stock-based compensation $1.20 - $1.30

    DD&A $23.00 - $25.00

    Exploration $1.50 - $2.50

    Interest expense ($ MM)

    Cash $210 - $220

    Non-cash $10

    Income tax rate (%) 38%

    Current taxes ($ MM) $40 - $50

    Capital expenditures ($ BN) $1.8 - $2.0

    19

    UPDATED AS OF

    JULY 29, 2015

    Note: Capital program excludes unbudgeted acquisitions.

  • Hedge Position

    2H15 OIL HEDGES

    65.7 MBopd

    ~78% Production1

    20

    (a) The index prices for the oil contracts are based on the New York Mercantile Exchange (“NYMEX”) – West Texas Intermediate

    (“WTI”) monthly average futures price.

    (b) The basis differential price is between Midland – WTI and Cushing – WTI.

    (c) The index prices for the natural gas price swaps are based on the NYMEX – Henry Hub last trading day futures price.

    (d) The basis differential price is between the El Paso Permian delivery point and NYMEX – Henry Hub delivery point.

    2016 OIL HEDGES

    49.3 MBopd

    1Based on 2015 production guidance midpoint.

    UPDATED AS OF

    AUGUST 31, 2015

    2015

    Third Quarter Fourth Quarter Total 2016 2017

    Oil Swaps: (a)

    Volume (Bbl) 6,169,000 5,924,000 12,093,000 18,059,000 7,038,000

    Price per Bbl $ 75.14 $ 73.68 $ 74.43 $ 75.71 $ 63.47

    Oil Basis Swaps: (b)

    Volume (Bbl) 5,841,000 5,428,000 11,269,000 17,223,000 6,335,000

    Price per Bbl $ (2.48) $ (2.41) $ (2.45) $ (1.77) (1.51)

    Natural Gas Swaps: (c)

    Volume (MMBtu) 5,980,000 5,980,000 11,960,000 21,960,000

    Price per MMBtu $ 4.16 $ 4.16 $ 4.16 $ 3.10

    Natural Gas Basis Swaps: (d)

    Volume (MMBtu) 1,380,000 1,380,000 2,760,000

    Price per MMBtu $ (0.13) $ (0.13) $ (0.13)

  • EBITDAX Reconciliation (Unaudited)

    21

    The Company defines EBITDAX as net income (loss), plus (1) exploration and abandonments expense, (2) depreciation, depletion and amortization expense, (3) accretion expense, (4) impairment of of

    long-lived assets, (5) non-cash stock-based compensation expense, (6) bad debt expense, (7) ineffective portion of cash flow hedges, (8) (gain) loss on derivatives not designated as hedges, (9) cash

    receipts from (payments on) derivatives not designated as hedges, (10) (gain) loss on disposition of assets and other, (11) interest expense, (12) loss on extinguishment of debt, (13) federal and state

    income taxes from continuing operations and (14) similar items listed above that are presented in discontinued operations. EBITDAX is not a measure of net income (loss) or cash flows as determined by

    GAAP.

    The Company’s EBITDAX measure provides additional information which may be used to better understand the Company’s operations. EBITDAX is one of several metrics that the Company uses as a

    supplemental financial measurement in the evaluation of its business and should not be considered as an alternative to, or more meaningful than, net income (loss) as an indicator of operating

    performance. Certain items excluded from EBITDAX are significant components in understanding and assessing a company's financial performance, such as a company's cost of capital and tax structure,

    as well as the historic cost of depreciable assets, none of which are components of EBITDAX. EBITDAX, as used by the Company, may not be comparable to similarly titled measures reported by other

    companies. The Company believes that EBITDAX is a widely followed measure of operating performance and is one of many metrics used by the Company’s management team and by other users of the

    Company’s consolidated financial statements. For example, EBITDAX can be used to assess the Company’s operating performance and return on capital in comparison to other independent exploration

    and production companies without regard to financial or capital structure, and to assess the financial performance of the Company’s assets and the Company without regard to capital structure or

    historical cost basis.

    (in thousands) 2014 2013 2012 2011 2010 2009 2008 2007

    Net Income (loss) $ 538,175 $ 251,003 $ 431,689 $ 548,137 $ 204,370 $ (9,802) $ 278,702 $ 25,360

    Exploration and abandonments 284,821 109,549 39,840 11,394 10,130 10,632 37,617 29,097

    Depreciation, depletion and amortization 979,740 772,608 575,128 400,022 211,487 162,975 95,240 49,262

    Accretion of discount on asset retirement obligations 7,072 6,047 4,187 2,444 1,079 690 510 296

    Impairments of long-lived assets 447,151 65,375 - 439 11,614 7,880 8,382 4,777

    Non-cash stock-based compensation 47,130 35,078 29,872 19,271 12,931 9,040 5,223 3,841

    Bad debt expense - - - - 870 (1,035) 2,905 -

    Ineffective portion of cash flow hedges - - - - - - (1,336) 821

    (Gain) loss on derivatives not designated as hedges (890,917) 123,652 (127,443) 23,350 87,325 156,857 (249,870) 20,274

    Cash receipts from (payments on) derivatives not

    designated as hedges 71,983 (32,341) 23,536 (84,854) (13,824) 82,416 (6,354) 1,815

    (Gain) loss on disposition of assets, net 9,308 1,268 372 1,139 58 114 (777) (368)

    Interest expense 216,661 218,581 182,705 118,360 60,087 28,292 29,039 36,042

    Loss on extinguishment of debt 4,316 28,616 - - - - - -

    Income tax expense (benefit) from continuing operations 317,785 118,237 251,041 261,800 101,613 (28,890) 148,230 8,673

    Discontinued operations - (12,081) 64,701 (26,343) 55,254 56,039 53,792 37,502

    EBITDAX 2,033,225$ 1,685,592$ 1,475,628$ 1,275,159$ 742,994$ 475,208$ 401,303$ 217,392$

    Years Ended December 31,