Investor Presentation J.P. Morgan Global High Yield and Leveraged Finance Conference FEBRUARY 2016

Investor Presentation J.P. Morgan Global High Yield and Leveraged Finance Conference FEBRUARY 2016

Forward-Looking Statements and Other Disclaimers 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 risk factors discussed or referenced in the Company's most recent Form 10-K and Current Reports on Form 8-K; risks relating to declines in the prices the Company receives, or sustained depressed 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; 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; the impact of potential changes in the Company s credit ratings; 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 risk-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 adjusted net income, adjusted EPS, EBITDAX and adjusted cash flows. 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 adjusted net income, adjusted EPS, EBITDAX and adjusted cash flows to the nearest comparable measures in accordance with GAAP, please see the appendix. We also disclose reserves replacement ratio and finding and development costs in this presentation. Please see the appendix for an explanation of how we calculate these metrics. 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, 2015 are estimated utilizing SEC reserve recognition standards and pricing assumptions based on the trailing 12-month average first-day-of-the-month prices of $46.79 per Bbl of oil and $2.59 per MMBtu of natural gas. The Company s estimate of its total proved reserves at December 31, 2015 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. 2

Concho Resources Premier Permian Basin Assets New Mexico Shelf Strategic acreage position in the Permian Basin ~1 million gross (650,000 net) acres Delaware Basin Midland Basin Core areas in the Delaware Basin, Midland Basin and New Mexico Shelf High-quality, long-life reserve base 623.5 MMBoe estimated proved reserves ~5 BBoe of total resource potential, including proved reserves ~18,000 horizontal drilling locations identified Building value through the cycle Maximizing resource recovery and reducing costs CXO Acreage High grading portfolio with strategic bolt-on acquisitions and opportunistic asset sales Protecting financial strength and future optionality with capital discipline 3

2015 Highlights Meeting Near-Term Objectives, Focusing on Long-Term Value Creation Operational Delivered record growth Annual production 143.3 MBoepd, up 28% over 2014 Oil production 94.4 MBopd, up 31% over 2014 Organic reserve additions 291% proved reserves replacement ratio Financial Solid financial results $0.54 diluted EPS; $0.91 adjusted EPS 1 EBITDAX 1 of $1.7bn Cost control Per-unit cost structure in-line or below the low-end of guidance Strategic Capital flexibility, discipline Reduced 2015 capital program 28% year-over-year 2H15 adjusted cash flow exceeded drilling & completion capital by $226mm 1 High-quality resource capture Permian expertise and drilling program expanded resource 35% 2016 OUTLOOK Exercise capital discipline Balance capital and cash flow Preserve financial strength and highquality resource Improve field development through increased pad drilling Improved capital efficiency Strengthened balance sheet Active portfolio management Optimized completions, long laterals and cost control Drill-bit F&D $11.66/Boe Enhanced liquidity YE15 net debt-to-ebitdax 1 of 1.8x Acquisitions and trades high grade inventory within core areas 1 Adjusted EPS, EBITDAX and adjusted cash flows are non-gaap measures. See appendix for reconciliations to GAAP measures. Drilling and completion capital is calculated as the sum of exploration and development costs incurred. Note: See appendix for an explanation of reserves replacement ratio and drill-bit F&D costs. 4

Capital Discipline Preserving Financial Strength & High-Quality Resource Reducing Capital Slowing Activity Resilient Production Exploration & Development Costs Incurred ($bn) Rig Count Avg. Daily Production (MBoepd) $2.6 33 143 136-143 $1.8 112 $0.9 - $1.1 18 11 2014 2015 2016e Hedges and minimum drilling commitments maximize flexibility Maintain financial strength 2014 2015 2016e Scale back capital plan, rigs and growth Preserve high-quality resource 2014 2015 2016e Optimize development Shallower PDP decline year-over-year 5

Performance Track Record Delivering Growth in a Price-Supportive Environment Production Oil Production (MBopd) Total Production (MBoepd) 143.3 Leading Permian production growth 2015 production up 28% over 2014, exceeding initial expectations of 16%-20% growth 2-year production CAGR 25% 92.2 112.0 94.4 Capital efficient oil growth 2015 oil production up 31% over 2014 2-year oil production CAGR 28% Per-unit LOE stable over 3-year period 72.1 57.9 Performance track record demonstrates ability to deliver future growth in a better commodity price environment 2013 2014 2015 6

Capital Efficiency Improvement Solid Reserve Additions at Low Cost Year-End Proved Reserves Delaware Basin Growth Engine Proved Reserves (MMBoe) SEC Oil Price Delaware Basin Proved Reserves (MMBoe) 700 $93.42 $91.48 100 315.8 90 600 637.2 623.5 80 500 400 300 200 502.9 SEC Oil Price -49% y/y $46.79 70 60 50 40 30 243.8 20 100 10 138.1 Drill-Bit F&D ($/Boe) 0 2013 2014 2015 $16.79 $14.02 $11.66 0 Added 157.1 MMBoe of proved reserves through extensions and discoveries Proved reserves replacement ratio 291% All-in F&D cost $13.77/Boe 2013 2014 2015 High-impact, resource-rich core asset Delaware Basin proved reserves up 30% year-overyear despite significant decline in commodity prices Note: Reserves replacement ratio and F&D costs exclude price-related revisions. See appendix for an explanation of reserves replacement ratio and F&D costs. 7

Resource Capture Expanding Resource Provides Solid Platform for Future Growth Asset Total Horizontal Drilling Inventory (Gross) Economic Resource (>20% ROR) $40/Bbl & $2.50/Mcf Horizontal Drilling Inventory (Gross) Inventory Life (Years) Primary Sources of Expansion ~5 BILLION BOE Horizontal resource potential (net) Northern Delaware Basin Southern Delaware Basin Midland Basin 11,700 2,700 46 Avalon Oil Shale & Wolfcamp 1,200 350 10 Wolfcamp 3,100 1,300 29 Wolfcamp & Lower Spraberry HIGH-QUALITY RESOURCE CAPTURE Inventory high grading Transitioned vertical drilling inventory to horizontal Zone delineation Tighter well spacing New Mexico Shelf 2,000 520 12 Yeso Total Horizontal Drilling Inventory of ~18,000 Locations ~30% of Inventory Generates >20% ROR at $40 Oil Note: Economic resource >20% ROR assumes $40/Bbl of oil and $2.50/Mcf of gas; years of drilling inventory based on 2016e drilling activity. 8

2016 Capital Plan Protecting Future Optionality with Capital Discipline 2016 Capital Allocation Drilling & Completion Activity 10% Facilities, Midstream Investments, G&G and Other 90% 2016 capital plan $1.1bn to $1.3bn 1 Reduced from initial $1.4bn base budget ~35% less capital year-over-year 1 Balancing capital and cash flow Production outlook flat-to-down ~5% vs. 2015 Production outlook driven by reducing activity, shifting to pad development and timing of completion activity Northern Delaware Basin Southern Delaware Basin 10% 25% Midland Basin New Mexico Shelf 45% Average 11 rigs in 2016 ~100% horizontal development Continued focus on maximizing resource recovery Optimizing well spacing and completion techniques throughout core areas 20% 1 2016 capital plan excludes acquisitions. Year-over-year capital comparison excludes acquisitions and is based on midpoint of 2016 capital plan guidance of $1.2bn. 9

Southern Delaware Basin Consolidating High-Quality Acreage ACREAGE POSITION ~200,000 gross (125,000 net) acres CURRENT RIG COUNT 2 Horizontal Rigs REEVES WARD North Harpoon Acquisition Adds ~12,000 net acres of core leasehold Privately negotiated transaction Consolidator of choice Seller accepts CXO equity as part of consideration and retains 20% nonoperated interest PECOS Big Chief Acreage Exchange Acreage swap consolidates ~21,000 net acres Increases operated acreage Optimizes development with more efficient longlaterals Adding scale and long-lateral drilling locations in our core Southern Delaware position CXO Acreage CXO 4Q15 HZ well North Harpoon Acquisition Acreage Exchange Note: Acreage as of December 31, 2015, pro forma for North Harpoon acquisition. Well results represent wells with >30 days of production data in 4Q15. 10

Strong Financial Position STRONG FINANCIAL POSITION Recent transactions reduce leverage metrics & increase liquidity RATING AGENCIES CONFIRM RATINGS S&P and Moody s recently confirmed Concho s corporate credit ratings (BB+/Ba1) ($ in millions) Pro Forma Balance Sheet as of 12/31/2015 (Unaudited) Cash $ 229 $ (150) $ 290 $ 369 Long-term debt: Actual 12/31/2015 North Harpoon Acquisition 1 Adjustments Loving County Divestiture 2 Pro Forma 12/31/2015 Credit facility 3 $ - $ - Senior notes $ 3,350 $ 3,350 Unamortized original issue premium & deferred loan costs, net $ (18) $ (18) Total long-term debt $ 3,332 $ 3,332 Stockholders' equity $ 6,943 $ 193 $ 7,136 Total capitalization $ 10,275 $ 10,468 Liquidity $ 2,729 $ 2,869 Net debt $ 3,103 $ 2,963 Net debt / net capitalization 31% 29% 1 North Harpoon acquisition purchase price includes 2.2mm shares of CXO common stock and $150mm cash. Value of equity consideration based on CXO closing price on 2/15/2016 of $87.15. 2 Anticipated Loving County divestiture proceeds total $290mm cash. 3 Credit facility has a borrowing base of $3.25bn and commitments of $2.5bn. 11

Track Record of Prudent Financial Management Debt Maturity Profile 1 ($ millions) Credit Facility $2.5bn credit facility undrawn 4.25x debt-to-ebitdax leverage covenant Senior Notes No maturities until 2021 $2,500 $2,000 $1,500 $1,000 $500 $0 Credit facility 7.000% Senior Unsecured 6.500% Senior Unsecured 5.500% Senior Unsecured 5.500% Senior Unsecured $2,500 $600 $1,550 $600 $600 2016 2017 2018 2019 2020 2021 2022 2023 1.4x 1.8x Avg. 1.6x 1.8x FYE Net Debt-to-EBITDAX 2 2.2x 2.1x 2.2x 1.6x 1.7x 1.8x 2007 2008 2009 2010 2011 2012 2013 2014 2015 1 All values shown at par. 2 EBITDAX is a non-gaap measure. See appendix for reconciliation to GAAP measure. 12

Volume (Bcf) Volume (MMBo) Disciplined Hedging Program 25 20 Oil Hedges ($ / Bbl) Oil Swaps Oil Basis Swaps 1 2 $70.13 ($1.46) 15 10 5 $71.99 ($1.46) $73.38 ($1.46) $74.21 ($1.46) $59.38 ($1.48) $57.39 ($0.90) 0 1Q16 2Q16 3Q16 4Q16 2016 2017 35 30 25 20 15 10 5 0 Natural Gas Hedges ($ / MMBtu) Natural Gas Swaps $3.02 $3.02 $3.02 $3.02 $3.02 1Q16 2Q16 3Q16 4Q16 2016 2017 3 Note: As of February 24, 2016 1 The index prices for the oil contracts are based on the New York Mercantile Exchange (NYMEX) West Texas Intermediate (WTI) monthly average futures price. 2 The basis differential price is between Midland WTI and Cushing WTI. 3 The index prices for the natural gas price swaps are based on the NYMEX Henry Hub last trading day futures price. 13

Creating Value Through the Cycle Proven strategy, experienced team and high-quality assets to weather commodity price cycles 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 14

Appendix

Northern Delaware Basin Industry-Leading Position with Multi-Zone Potential ACREAGE POSITION ~355,000 gross (250,000 net) acres EDDY Resource Expansion Avalon Shale and Wolfcamp multi-zone delineation and downspacing primary resource growth contributors CURRENT RIG COUNT 6 Horizontal Rigs ALPHA CRUDE CONNECTOR (ACC) 400-mile pipeline system 100+ MBopd capacity Improves upstream price realizations LEA CULBERSON REEVES LOVING CXO Acreage CXO 4Q15 HZ well ACC 4Q15 Well Results Added 24 horizontal wells (avg. lateral length 4,785 ) Avg. 30-day peak rate: 957 Boepd (74% oil) Avg. 24-hour peak rate: 1,445 Boepd 2016 Plans Pad drilling to drive operational efficiencies Primary targets include 2 nd Bone Spring, Avalon and Wolfcamp Continue Avalon well-spacing evaluation Note: Acreage as of December 31, 2015, pro forma for acreage divestiture. Well results represent wells with >30 days of production data in 4Q15. 16

Southern Delaware Basin Consolidating High-Quality Acreage ACREAGE POSITION ~200,000 gross (125,000 net) acres CURRENT RIG COUNT 2 Horizontal Rigs REEVES WARD PECOS Resource Expansion Optimizing field development and well spacing High grading inventory and increasing long-lateral drilling opportunities 2016 Plans Focused development on Wolfcamp Recently Announced Transactions North Harpoon acquisition adds ~12,000 net acres of core leasehold Acreage exchange consolidates ~21,000 net acres, increasing operated acreage CXO Acreage CXO 4Q15 HZ well North Harpoon Acquisition Acreage Exchange 4Q15 Well Results Added 5 horizontal wells (avg. lateral length 6,867 ) Avg. 30-day peak rate: 1,199 Boepd (78% oil) Avg. 24-hour peak rate: 1,498 Boepd Note: Acreage as of December 31, 2015, pro forma for North Harpoon acquisition. Well results represent wells with >30 days of production data in 4Q15. 17

Midland Basin Optimizing Development HORIZONTAL CORE ACREAGE POSITION ~200,000 gross (110,000 net) acres CURRENT RIG COUNT 1 Horizontal Rig ANDREWS ECTOR CRANE MARTIN MIDLAND Resource Expansion Inventory quality improving converted vertical drilling locations to horizontal Optimizing Wolfcamp well spacing Successful Lower Spraberry testing 2016 Plans Build on long-lateral success: substantially all development will be 2-mile laterals and utilize pad drilling Optimize completion technique Advance Lower Spraberry program Test well spacing, development pattern UPTON 4Q15 Well Results Added 5 horizontal wells (avg. lateral length 6,634 ) Avg. 30-day peak rate: 835 Boepd (85% oil) Avg. 24-hour peak rate: 1,099 Boepd CXO Acreage CXO 4Q15 HZ well Note: Acreage as of December 31, 2015. Well results represent wells with >30 days of production data in 4Q15. 18

New Mexico Shelf Enhancing Value in Legacy Oil Play ACREAGE POSITION ~150,000 gross (100,000 net) acres Resource Expansion Horizontal drilling improving resource recovery CURRENT RIG COUNT 1 Horizontal Rig CXO Acreage CXO 4Q15 HZ well EDDY LEA 2016 Plans Rate-of-return competitive at low oil prices Focus on Upper Blinebry and Paddock Optimize well spacing and completion techniques 4Q15 Well Results Added 10 horizontal wells (avg. lateral length 4,246 ) Avg. 30-day peak rate: 354 Boepd (81% oil) Avg. 24-hour peak rate: 497 Boepd Note: Acreage as of December 31, 2015. Well results represent wells with >30 days of production data in 4Q15. 19

2016 Operational & Financial Outlook FIRST QUARTER & FULL-YEAR 2016 OUTLOOK UPDATED AS OF FEBRUARY 24, 2016 1Q16 Guidance Production (MBoepd) 130-134 Crude oil differential to NYMEX ($/Bbl) ($4.50) - ($4.70) LOE ($/Boe) $7.75 - $8.00 2016 Guidance Production Annual growth -5% - 0% Oil mix 60% - 64% Price realizations, excluding commodity derivatives Crude oil differential to NYMEX ($/Bbl) ($3.75) - ($4.25) Natural gas (per Mcf) (% of NYMEX) 80% - 85% Operating costs and expenses ($/Boe, unless noted) LOE $7.50 - $8.00 Oil & gas taxes (% of oil & gas revenues) 8.25% G&A: Cash G&A $3.10 - $3.50 Non-cash stock-based compensation $1.35 - $1.45 DD&A $24.00 - $26.00 Exploration and other $1.00 - $2.00 Interest expense ($mm): Cash $205 - $215 Non-cash $10 Income tax rate (%) 38% Current taxes ($mm) $0 - $10 Capital plan ($bn) 1 $1.1 - $1.3 1 Capital plan excludes acquisitions. 20

Adjusted Net Income and Adjusted EPS Reconciliation (Unaudited) The following table provides a reconciliation from the United States generally accepted accounting principles (GAAP) measure of net income to adjusted net income (non-gaap) for the periods indicated: Years Ended December 31, (in thousands, except per share amounts) 2015 2014 Net income - as reported $ 65,900 $ 538,175 Adjustments for certain non-cash and unusual items: Gain on derivatives (699,752) (890,917) Cash receipts from derivatives 632,916 71,983 Impairments of long-lived assets 60,529 447,151 Leasehold abandonments 34,532 217,326 Loss on extinguishment of debt - 4,316 Loss on disposition of assets and other 57,671 10,389 Tax impact (31,953) 53,106 Change in statutory effective income tax rates (9,026) (7,945) Adjusted net income $ 110,817 $ 443,584 Adjusted earnings per share: Basic $ 0.92 $ 4.03 Diluted $ 0.91 $ 4.02 Tax rates 37.2% 38.0% 21

EBITDAX Reconciliation (Unaudited) The Company defines EBITDAX as net income, plus (1) exploration and abandonments expense, (2) depreciation, depletion and amortization expense, (3) accretion expense, (4) impairments of long-lived assets, (5) non-cash stock-based compensation expense, (6) gain on derivatives, (7) cash receipts from derivatives, (8) loss on disposition of assets and other, (9) interest expense, (10) loss on extinguishment of debt and (11) federal and state income taxes. EBITDAX is not a measure of net income 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 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. The following table provides a reconciliation of the GAAP measure of net income to EBITDAX (non-gaap) for the periods indicated: (in thousands, except per share amounts) Years Ended December 31, 2015 2014 Net income $ 65,900 $ 538,175 Exploration and abandonments 58,847 284,821 Depreciation, depletion and amortization 1,223,253 979,740 Accretion of discount on asset retirement obligations 7,600 7,072 Impariments of long-lived assets 60,529 447,151 Non-cash stock-based compensation 63,073 47,130 Gain on derivatives (699,752) (890,917) Cash receipts from derivatives 632,916 71,983 Loss on disposition of assets and other 53,789 9,308 Interest expense 215,384 216,661 Loss on extinguishment of debt - 4,316 Income tax expense 31,371 317,785 EBITDAX $ 1,712,910 $ 2,033,225 22

Adjusted Cash Flows Reconciliation (Unaudited) The following table provides a reconciliation of the GAAP measure of cash flows from operating activities to adjusted cash flows (non-gaap) for the periods indicated: (in thousands) Cash flows from operating activities $ 897,505 $ 1,673,787 Settlements received from derivatives (a) 632,916 71,983 Adjusted cash flows $ 1,530,421 $ 1,745,770 (a) Amounts are presented in cash flows from investing activities for GAAP purposes. Years Ended December 31, 2015 2014 23

Reserves Replacement Ratio & Finding & Development Costs (Unaudited) Reserves Replacement Ratio Reserves replacement ratio is a non-gaap measure. The Company uses the reserves replacement ratio as an indicator of the Company s ability to replenish annual production volumes and grow its reserves, thereby providing some information on the sources of future production. The reserves replacement ratio is a statistical indicator that is limited because it typically varies widely based on the extent and timing of discoveries and property acquisitions. Its predictive and comparative value is also limited for the same reasons. In addition, since the ratio does not embed the cost or timing of future production of new reserves, it cannot be used as a measure of value creation. The reserves replacement ratio of approximately 291% was calculated by dividing net proved reserve additions of 152.2 MMBoe (the sum of extensions, discoveries, revisions other than price-related revisions and purchases) by production of 52.3 MMBoe. Drill-Bit F&D Cost Drill-bit finding and development cost is a non-gaap measure used to assist in an evaluation of how much it costs the Company, on a per Boe basis, to add proved reserves. Drill-bit finding and development costs are calculated by dividing the sum of exploration costs and development costs of $1.8 billion by total reserve extensions and discoveries of 157.1 MMBoe. This calculation does not include the future development costs required for the development of proved undeveloped reserves. All-In F&D Cost All-in finding and development costs are calculated by dividing the total costs incurred of $2.1 billion by the sum of total reserve extensions and discoveries, reserve revisions other than price and purchases of reserves-in-place of 152.1 MMBoe. This calculation does not include the future development costs required for the development of proved undeveloped reserves. 24