Investor Presentation · 2/25/2016 · Investor Presentation MARCH 2016 . Forward-Looking Statements and Other Disclaimers 2 This presentation contains “forward-looking statements”

Investor Presentation

MARCH 2016

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 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.

Concho Resources

3

Strategic acreage position in the Permian Basin • ~1 million gross (650,000 net) acres

• 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

• High grading portfolio with strategic bolt-on acquisitions and opportunistic asset sales

• Protecting financial strength and future optionality with capital discipline

Premier Permian Basin Assets

CXO Acreage

Delaware Basin

New Mexico Shelf

Midland Basin

4 1Adjusted 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.

Operational Delivered record growth

• Annual production 143.3 MBoepd, up 28% over 2014

• Oil production 94.4 MBopd, up 31% over 2014

Financial Solid financial results

• $0.54 diluted EPS; $0.91 adjusted EPS1

• EBITDAX1 of $1.7bn

Strategic

2015 Highlights Meeting Near-Term Objectives, Focusing on Long-Term Value Creation

Capital flexibility, discipline • Reduced 2015 capital

program 28% year-over-year

• 2H15 adjusted cash flow exceeded drilling & completion capital by $226mm1

2016 OUTLOOK • Exercise capital

discipline • Balance capital and

cash flow • Preserve financial

strength and high-quality resource

• Improve field development through increased pad drilling

Organic reserve additions • 291% proved reserves

replacement ratio

Improved capital efficiency • Optimized completions, long

laterals and cost control • Drill-bit F&D $11.66/Boe

Cost control • Per-unit cost structure in-line

or below the low-end of guidance

Strengthened balance sheet • Enhanced liquidity • YE15 net debt-to-EBITDAX1

of 1.8x

High-quality resource capture • Permian expertise and drilling

program expanded resource 35%

Active portfolio management • Acquisitions and trades high

grade inventory within core areas

Capital Discipline Preserving Financial Strength & High-Quality Resource

2014 2015 2016e

$2.6

$1.8

$0.9 - $1.1

Reducing Capital

• Hedges and minimum drilling commitments maximize flexibility

• Maintain financial strength

33

18

11

2014 2015 2016e

Slowing Activity Exploration & Development Costs Incurred ($bn)

• Scale back capital plan, rigs and growth

• Preserve high-quality resource

Rig Count

112

143

2014 2015 2016e

Resilient Production

• Optimize development • Shallower PDP decline year-over-year

5

136 - 143

Avg. Daily Production (MBoepd)

Performance Track Record Delivering Growth in a Price-Supportive Environment

6

57.9

72.1

94.4 92.2

112.0

143.3

2013 2014 2015

Production Leading Permian production growth • 2015 production up 28% over 2014, exceeding

initial expectations of 16%-20% growth • 2-year production CAGR 25%

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

Oil Production (MBopd) Total Production (MBoepd)

Performance track record demonstrates ability to deliver future growth in a

better commodity price environment

Capital Efficiency Improvement Solid Reserve Additions at Low Cost

7

• Added 157.1 MMBoe of proved reserves through extensions and discoveries

• Proved reserves replacement ratio 291% • All-in F&D cost $13.77/Boe

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.

138.1

243.8

315.8

2013 2014 2015

Delaware Basin Growth Engine

Delaware Basin Proved Reserves (MMBoe)

High-impact, resource-rich core asset • Delaware Basin proved reserves up 30% year-over-

year despite significant decline in commodity prices

502.9

637.2 623.5

$93.42 $91.48

$46.79

0

10

20

30

40

50

60

70

80

90

100

0

100

200

300

400

500

600

700

2013 2014 2015

Proved Reserves (MMBoe) SEC Oil Price

Year-End Proved Reserves

$16.79 $14.02 $11.66 Drill-Bit F&D ($/Boe)

SEC Oil Price -49% y/y

Resource Capture Expanding Resource Provides Solid Platform for Future Growth

~5 BILLION BOE Horizontal resource

potential (net)

8 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.

HIGH-QUALITY RESOURCE CAPTURE

• Inventory high grading

• Transitioned vertical drilling inventory to horizontal

• Zone delineation • Tighter well spacing

Asset Total Horizontal Drilling Inventory

(Gross)

Primary Sources of Expansion

Northern Delaware Basin

Southern Delaware Basin

Midland Basin

New Mexico Shelf

11,700 2,700 46 Avalon Oil Shale &

Wolfcamp

1,200 350 10 Wolfcamp

3,100 1,300 29 Wolfcamp & Lower

Spraberry

2,000 520 12 Yeso

Total Horizontal Drilling Inventory of ~18,000 Locations ~30% of Inventory Generates >20% ROR at $40 Oil

Horizontal Drilling Inventory

(Gross)

Inventory Life

(Years)

Economic Resource (>20% ROR) $40/Bbl & $2.50/Mcf

2016 Capital Plan Protecting Future Optionality with Capital Discipline

9

2016 Capital Allocation

45%

20%

25%

10%

Average 11 rigs in 2016 • ~100% horizontal development

Continued focus on maximizing resource recovery • Optimizing well spacing and completion techniques

throughout core areas

90%

10%

2016 capital plan $1.1bn to $1.3bn1 • Reduced from initial $1.4bn base budget • ~35% less capital year-over-year1 • 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

Drilling & Completion Activity

Facilities, Midstream Investments, G&G and Other

Northern Delaware Basin Southern Delaware Basin

Midland Basin New Mexico Shelf

12016 capital plan excludes acquisitions. Year-over-year capital comparison excludes acquisitions and is based on midpoint of 2016 capital plan guidance of $1.2bn.

Northern Delaware Basin Industry-Leading Position with Multi-Zone Potential

ACREAGE POSITION ~355,000 gross

(250,000 net) acres

CURRENT RIG COUNT

6 Horizontal Rigs

Note: Acreage as of December 31, 2015, pro forma for acreage divestiture. Well results represent wells with >30 days of production data in 4Q15. 10

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

CXO Acreage CXO 4Q15 HZ well ACC

• Pad drilling to drive operational efficiencies • Primary targets include 2nd Bone Spring,

Avalon and Wolfcamp • Continue Avalon well-spacing evaluation

2016 Plans

EDDY

LEA

CULBERSON REEVES LOVING

• Avalon Shale and Wolfcamp multi-zone delineation and downspacing primary resource growth contributors

Resource Expansion

ALPHA CRUDE CONNECTOR (ACC)

• 400-mile pipeline system

• 100+ MBopd capacity

• Improves upstream price realizations

Southern Delaware Basin Consolidating High-Quality Acreage


(125,000 net) acres

CURRENT RIG COUNT

2 Horizontal Rigs

11

WARD

CXO Acreage North Harpoon Acquisition Acreage Exchange

REEVES

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

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.


• Avg. 30-day peak rate: 1,199 Boepd (78% oil) • Avg. 24-hour peak rate: 1,498 Boepd

PECOS

• Optimizing field development and well spacing • High grading inventory and increasing long-lateral

drilling opportunities

Resource Expansion

CXO 4Q15 HZ well

Midland Basin Optimizing Development

HORIZONTAL CORE ACREAGE POSITION

~200,000 gross (110,000 net) acres

CURRENT RIG COUNT

1 Horizontal Rig

12

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


• Avg. 30-day peak rate: 835 Boepd (85% oil) • Avg. 24-hour peak rate: 1,099 Boepd

CXO Acreage CXO 4Q15 HZ well

MARTIN

MIDLAND

UPTON

ANDREWS

ECTOR

CRANE

• Inventory quality improving – converted vertical drilling locations to horizontal

• Optimizing Wolfcamp well spacing • Successful Lower Spraberry testing

Resource Expansion

Note: Acreage as of December 31, 2015. Well results represent wells with >30 days of production data in 4Q15.

New Mexico Shelf Enhancing Value in Legacy Oil Play


(100,000 net) acres

CURRENT RIG COUNT

1 Horizontal Rig

13

CXO Acreage CXO 4Q15 HZ well

• Rate-of-return competitive at low oil prices

• Focus on Upper Blinebry and Paddock • Optimize well spacing and completion

techniques


• Avg. 30-day peak rate: 354 Boepd (81% oil) • Avg. 24-hour peak rate: 497 Boepd

2016 Plans EDDY LEA

• Horizontal drilling improving resource recovery

Resource Expansion

Note: Acreage as of December 31, 2015. Well results represent wells with >30 days of production data in 4Q15.

Strong Financial Position

1North 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. 2Anticipated Loving County divestiture proceeds total $290mm cash. 3Credit facility has a borrowing base of $3.25bn and commitments of $2.5bn.

STRONG FINANCIAL POSITION

Recent transactions reduce leverage

metrics & increase liquidity

14

Pro Forma Balance Sheet as of 12/31/2015 (Unaudited)

RATING AGENCIES CONFIRM RATINGS S&P and Moody’s

recently confirmed Concho’s corporate

credit ratings (BB+/Ba1)

Cash 229$ (150)$ 290$ 369$

Long-term debt:Credit facility3 -$ -$ 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%

($ in millions)

Actual 12/31/2015

AdjustmentsPro Forma12/31/2015North Harpoon

Acquisition1Loving County

Divestiture2

Creating Value Through the Cycle

15

Proven strategy, experienced team and high-quality assets to weather commodity price cycles

Maintaining superior positioning for growth acceleration

Improving capital productivity

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

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

Appendix

5.500% Senior Unsecured

Track Record of Prudent Financial Management

17

$2,500

$600 $600

$1,550 $600

$0

$500

$1,000

$1,500

$2,000

$2,500

2016 2017 2018 2019 2020 2021 2022 2023

Debt Maturity Profile1 ($ millions)

Credit facility 5.500% Senior Unsecured 6.500% Senior Unsecured 7.000% Senior Unsecured Credit Facility • $2.5bn credit facility undrawn • 4.25x debt-to-EBITDAX leverage

covenant Senior Notes

• No maturities until 2021

1.4x 1.6x

1.8x

2.2x

1.6x

2.1x 2.2x

1.7x 1.8x

2007 2008 2009 2010 2011 2012 2013 2014 2015

FYE Net Debt-to-EBITDAX2

1.8x Avg.

1All values shown at par. 2EBITDAX is a non-GAAP measure. See appendix for reconciliation to GAAP measure.

Hedge Position

18

(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.

2016 OIL HEDGES 63.4 MBopd

UPDATED AS OF FEBRUARY 24, 2016

First Quarter

Second Quarter

Third Quarter

Fourth Quarter Total 2017

Oil Swaps: (a)Volume (Bbl) 6,722,000 5,985,000 5,460,000 5,054,000 23,221,000 15,642,000 Price per Bbl 71.99$ 73.38$ 74.21$ 59.38$ 70.13$ 57.39$

Oil Basis Swaps: (b)Volume (Bbl) 6,155,000 5,914,000 5,520,000 5,060,000 22,649,000 14,276,000 Price per Bbl (1.46)$ (1.46)$ (1.46)$ (1.48)$ (1.46)$ (0.90)$

Natural Gas Swaps: (c)Volume (MMBtu) 7,280,000 7,280,000 7,360,000 7,360,000 29,280,000 Price per MMBtu 3.02$ 3.02$ 3.02$ 3.02$ 3.02$

2016

2016 Operational & Financial Outlook

FIRST QUARTER & FULL-YEAR 2016

OUTLOOK

19

UPDATED AS OF FEBRUARY 24, 2016

1Capital plan excludes acquisitions.

Production (MBoepd) 130 - 134Crude oil differential to NYMEX ($/Bbl) ($4.50) - ($4.70)LOE ($/Boe) $7.75 - $8.00

ProductionAnnual 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 - $8.00Oil & gas taxes (% of oil & gas revenues)G&A:

Cash G&A $3.10 - $3.50Non-cash stock-based compensation $1.35 - $1.45

DD&A $24.00 - $26.00Exploration and other $1.00 - $2.00Interest expense ($mm):

Cash $205 - $215Non-cash

Income tax rate (%)Current taxes ($mm) $0 - $10Capital plan ($bn)1 $1.1 - $1.3

8.25%

$1038%

1Q16Guidance

2016 Guidance

Adjusted Net Income and Adjusted EPS Reconciliation (Unaudited)

20

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:

Net income - as reported $ 65,900 $ 538,175Adjustments for certain non-cash and unusual items:

Gain on derivatives (699,752) (890,917)Cash receipts from derivatives 632,916 71,983Impairments of long-lived assets 60,529 447,151Leasehold abandonments 34,532 217,326Loss on extinguishment of debt - 4,316Loss on disposition of assets and other 57,671 10,389Tax impact (31,953) 53,106Change in statutory effective income tax rates (9,026) (7,945)

Adjusted net income $ 110,817 $ 443,584Adjusted earnings per share:

Basic $ 0.92 $ 4.03Diluted $ 0.91 $ 4.02

Tax rates 37.2% 38.0%

(in thousands, except per share amounts) 2015 2014

Years EndedDecember 31,

EBITDAX Reconciliation (Unaudited)

21

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:

Net income $ 65,900 $ 538,175Exploration and abandonments 58,847 284,821Depreciation, depletion and amortization 1,223,253 979,740Accretion of discount on asset retirement obligations 7,600 7,072Impariments of long-lived assets 60,529 447,151Non-cash stock-based compensation 63,073 47,130Gain on derivatives (699,752) (890,917)Cash receipts from derivatives 632,916 71,983Loss on disposition of assets and other 53,789 9,308Interest expense 215,384 216,661Loss on extinguishment of debt - 4,316Income tax expense 31,371 317,785

EBITDAX $ 1,712,910 $ 2,033,225

(in thousands, except per share amounts)


2015 2014

Adjusted Cash Flows Reconciliation (Unaudited)

22

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:

Cash flows from operating activities $ 897,505 $ 1,673,787Settlements 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.

(in thousands)


2015 2014

Reserves Replacement Ratio & Finding & Development Costs (Unaudited)

23

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 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.

Reserves Replacement Ratio

Drill-Bit 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.

All-In F&D Cost

Documents

Investor Presentation · 2/25/2016 · Investor Presentation MARCH 2016 . Forward-Looking Statements and Other Disclaimers 2 This presentation contains “forward-looking statements”