Scotia Howard Weil Energy Conference

Scotia Howard Weil Energy Conference Rick Muncrief, President and CEO March 2-22, 206

Premier Asset Portfolio Coming Into Focus 2

WPX Profile: World-Class Delaware Position WPX TODAY World-Class Delaware acreage WILLISTON BASIN Core Williston basin position Leading San Juan acreage Multi-decade inventory SAN JUAN BASIN HEADQUARTERS TULSA, OK Balanced commodity mix PERMIAN BASIN Strong 206 hedge position Liquidity in place for prolonged downturn OIL NATURAL GAS Based on midpoint of guidance 3

206 Outlook Focused on Fewer Basins DELAWARE RECEIVING OVER 50% OF CAPEX Other <% D & C C A P I TA L MAINTAINING OPERATIONAL MOMENTUM Permian 5% San Juan 39% Piceance 6% Williston 29% Permian 5% Williston 28% San Juan 2% FLEXIBLE CAPITAL PROGRAM 205 6 BASINS ~$657MM Marcellus <% 206 3 BASINS $395MM MORE NIMBLE AND FOCUSED C O M M O D I T Y M I X 2% 2% BALANCED COMMODITY MIX 2% 67% 49% 39% MAINTAIN STRONG LIQUIDITY 205 206 Based on midpoint of guidance OIL NAT. GAS NGLS 4

$MM 207 % of Production Hedged WPX Pro-Forma Liquidity, Hedges and Debt Maturities Pro-Forma Liquidity Cash and Equivalents $4 Senior Notes Due 207 (304) Revolver Balance (355) Sale Proceeds,200 Net Proceeds 54 Undrawn Credit Facility,025 Total Pro-Forma Liquidity $,607 $,200 00% $3.79 80% $60.85 60% 40% 20% 0% Oil 206 2 Natural Gas 206 2 Pro-Forma Debt Maturity STRONG HEDGE POSITION ~75% of oil production hedged $60.85 per barrel Oil: 22,804 bbl/d Hedged Natural gas fully hedged $50.7 per barrel $3.79 per MMBtu $,000 $800 $600 $400 $200 Expect $.2B OF SALES PROCEEDS IN H OF 206 $,485 UNDRAWN $500 $,00 $500 $500 $0 206 207 208 209 2020 202 2022 2023 2024 Senior Notes Senior Notes Senior Notes Senior Notes Balance as of 2/9/206 2 Based on midpoint of guidance 5

$ per BOE $ per BOE $ per BOE Cost Continue to Trend Lower $4.00 $3.90 $3.80 $3.70 $3.60 $3.50 $3.40 $3.92 9% REDUCTION IN LOE PER BOE $3.58 $5.40 $5.20 $5.00 $4.80 $4.60 $4.40 $5.28 3% REDUCTION IN GP&T PER BOE $4.59 $3.30 YTD 204 YTD 205 FY 204 FY 205 $4.20 YTD FY 204 YTD FY 205 $4.30 $4.20 $4.0 $4.00 $3.90 $3.80 $3.70 $3.60 $3.50 $4.24 % REDUCTION IN G&A PER BOE $3.78 FY 204 FY 205 Excludes one-time expenses associated with Early Exit Program (204), Severance and Relocation (205) and RKI Retention (205) $0 -$2 -$4 -$6 -$8 -$0 -$2 FY 204 FY 205 -$0.6 -$7.6 33% IMPROVEMENT IN DIFFERENTIALS 6

9,000 Overview of WPX s World-Class Delaware Position ~94,000 TOTAL NET ACRES, ~60,000 NET ACRES NEAR STATELINE WOLFCAMP BELL CANYON CHERRY CANYON 2 PROSPECTIVE ZONES WITH 3,600++ GROSS LOCATIONS AVALON DELAWARE SANDS BRUSHY CANYON AVALON OWNED/OPERATED MIDSTREAM INFRASTRUCTURE FIRST BONE SPRING SECOND BONE SPRING.+ BILLION BARRELS OF EQUIVALENT NET RESOURCE POTENTIAL BONE SPRING THIRD BONE SPRING WOLFCAMP A WOLFCAMP B WOLFCAMP C WOLFCAMP D Includes ~,000 acres in Midland Basin Hydrocarbon Pay Indication 7

Cumulative MBOE 200 Delaware: Operational and Technical Momentum BASIN HIGHLIGHTS 80 Wolfcamp A exceeding acquisition assumptions 60 Up to 6 two-mile Wolfcamp A laterals in 206 40 Completion design changes 20 Reduced cost switching to self-sourcing model 00 Targeting additional zones in Wolfcamp A 80 60 PRE-ACQUISITION DESIGN CROSSLINK/HYBRID,,000 LBS/FT, 200-250 STAGE SPACING, 3 PERF CLUSTERS 40 20 0 00 50 50 POST-ACQUISITION DESIGN SLICKWATER/HYBRID,,500-2,000 LBS/FT, 200 STAGE SPACING, 4 PERF CLUSTERS Normalized Days On Production Vision:,000 MBOE WPX Now: 850 MBOE Acquisition: 670 MBOE 50 50 50 50 8

$0 $8 $6 $4 $2 $0 Rapid Progress in the Wolfcamp A and Just Getting Started D&C,2 EURS F&D Cost 43% REDUCTION RKI WPX Vision 200 000 800 600 400 200 0 85% INCREASE RKI WPX Vision $20.00 $5.00 $0.00 $5.00 $- 69% REDUCTION RKI WPX Vision Vision: $5.0MM Vision:,000 MBOE Vision: $5.00 per BOE RKI: 204-ACQUISITION WPX NOW WPX VISION Avg. 3,800 laterals 3 Avg. 4,000 laterals Avg. 4,750 laterals Avg.,000 lb/ft. of proppant Avg.,500 lb/ft. of proppant,500 lb/ft.+ of proppant Hybrid completion design Hybrid completion design Testing slick water completion design No Geosteering/3D seismic Increased density testing Geosteering/3D Seismic Target landing Target landing Wolfcamp Well Costs: October 203 August 205 2 Current Wolfcamp AFEs 3 Per 640 acre spacing unit 9

EUR, BOE Permian: Well and Economic Projections Wolfcamp A Type Well 00% Price Sensitivity Curve,250 Capital/EUR Sensitivity Curve 90% 80% Vision: $5.0MM D&C -,000 Mboe Current: $6.0MM D&C - 850 Mboe,50 B-tax ROR 70% 60% 50% 40%,050 950 850 Vision Current 30% 20% 0% 750 650 Acquisition Curve 0% $30 $40 $50 $60 $70 Flat WTI Oil Price 550 $4.0 $4.5 $5.0 $5.5 $6.0 $6.5 $7.0 $7.5 $8.0 $8.5 D&C, $MM 206 Assumptions Lateral Length: Current 4,000ft, Vision 4,750ft Current D&C: $6.0MM, Vision $5.0MM EUR: Current 850 MBOE, Vision,000 MBOE B-Factor:.3 Crude Differential: $3.50 GP&T per BOE: $0.58 LOE per BOE: $4.95 Avg Working Interest : 98% NRI : 75% Assumes $40/$2.70 flat price Based on 206 Guidance 0

Cumulative MBOE Cumulative MBOE Strong Results in Williston and San Juan Gallup WILLISTON BASIN HIGHLIGHTS Wells trending above type curve Complete 6 well pad mid-march Defer remaining completions 7-29 DUCS at year-end 206 250 200 50 00 Well cost remain low $6.0MM D&C 50 $.MM Artificial Lift and Facilities 0 0 40 80 20 60 200 Normalized Days of Production SAN JUAN BASIN HIGHLIGHTS Wells trending above type curve Record 6.5 days spud to rig release Set new drilling record 5,00ft in 26 hours Increased pounds of sand per lateral ft.,000+ lbs from 730 lbs West Lybrook 6 well pad st spud late Feb. 40 20 00 80 60 40 20 0 0 0 20 30 40 50 60 70 80 90 00 0 20 30 40 50 60 70 80 90 Normalized Days of Production Combined average of 6MM lb. wells and 0MM lb. wells

Execution Core to WPX PORTFOLIO REBALANCED IN CORE BASINS RAPID EXECUTION CREATES STRONG LIQUIDITY CONTINUED OPERATIONAL MOMENTUM IMPROVING COST STRUCTURE LEANER AND MORE NIMBLE COMPANY REMAIN OPPORTUNISTIC COMPLETED ~$.0B OF DIVESTITURES IN 205 $.2B IN CASH PROCEEDS EXPECTED H206 206 FLEXIBLE CAPITAL PROGRAM WPX begins 206 from a position of strength; core assets, proven execution, and strong liquidity ~75% OIL PRODUCTION HEDGED IN 206 2

APPENDIX

WPX Hedges Updated: March 6, 206 Q 206 Q2 Q4 206 207 Volume/Day Average Price Volume/Day Average Price Volume/Day Average Price Crude Oil (bbl) Fixed Price Swaps¹ 30,024 $6.08 29,66 $60.77 22,804 $50.7 Crude Oil Basis (bbl) Midland Basis Swaps 5,000 ($0.45) 5,000 ($0.45) - - Natural Gas (MMBtu) Fixed Price Swaps,2 43,97 3 $3.63 46,54 3 $3.93 30,000 $2.70 Natural Gas Basis (MMBtu) MidCon Basis Swaps 5,000 ($0.23) 5,000 ($0.23) - - Rockies Basis Swaps 99,34 ($0.2) 40,000 ($0.22) 40,000 ($0.22) San Juan Basis Swaps 00,000 ($0.8) 00,000 ($0.8) 32,500 ($0.6) SoCal Basis Swaps 45,000 ($0.0) 45,000 ($0.0) 0,000 $0.00 Permian Basis Swaps 32,500 ($0.7) 32,500 ($0.7) - - In connection with several natural gas and crude oil swaps, we entered into swaptions with the swap counterparties granting the counterparty the right, but not the obligation, to enter into an underlying swap with us in the future. Crude oil swaptions for 206 total,257 bbl/d at a weighted average strike price of $57.5. Natural gas swaptions for 207 total 65,000 MMBtu/d at a weighted average strike price of $4.9. Crude oil swaptions for 207 total 3,264 bbl/d at a weighted average strike price of $5.22. 2 Including the derivatives sold with the Piceance Basin, WPX has natural gas derivatives for 206 totaling 42,32 MMBtu/d at a weighted average price of $3.63 and 92,500 MMBtu/d at a weighted average price of $3.22 for 207. 3 Q 6 reflects our historical natural gas hedge position including Piceance volumes. 2Q 6-4Q 6 hedge volumes are impacted by the transfer of natural gas hedges to Terra as of April st 206. 4

MBOE/D Cum MBOE MBOE/D Cum MBOE Type Curve Assumptions: San Juan Gallup and Williston Type Curve: San Juan Gallup Type Curve: Williston 400 800,200 600 200 700,000 500 000 800 600 400 200 30 + Yrs 600 500 400 300 200 00 800 600 400 200 400 300 200 00 0 0 2 3 4 5 6 7 8 9 0 0 0 0 2 3 4 5 6 7 8 9 0 0 780 Mboe/d EUR CUM 780 Mboe 750 Mboe/d EUR Cum 750 Mboe San Juan Gallup Assumptions Williston Assumptions Lateral Length:.5 Mile D&C Cost: $5.08 EUR: 780 MBOE B-Factor:.4 Differential: ~$8.00 GP&T per BOE: $3.80 LOE per BOE: ~$6.00 Avg Working Interest 3 : 96.28% NRI 3 : 77.77% Lateral Length: 9,600 ft. D&C Cost: $7. EUR: 750 MBOE B-Factor:.6 Differential : ~$8.00 GP&T per BOE 2 : $.06 LOE per BOE: $6.92 Avg Working Interest 3 : 83.5% NRI 3 : 66.4% Wellhead differential of $5. and $2.86 of GP&T accounted for as a contra revenue 2 Excludes GP&T contra revenue 3 Based on 206 Guidance 5

Permian Overview ~94,000 net acres Currently operating ~3 rigs 3,600 gross risked locations Commodity mix 2 55% oil 28% natural gas 7% NGLs Available sales outlets Holley Frontier s Artesia, NM Refinery Western s El Paso Refinery Gulf Coast Cushing Midland Includes ~,000 acres in Midland Basin 2 4Q 205 6

Williston Overview ~85,000 net acres Currently operating rig 575+ gross drilling locations ~50 operated drilling locations ~70 non-op locations Commodity mix 85% oil 8% natural gas 7% NGLs Available sales outlets Clearbrook, Minn. (WTI) Guernsey, Wyo. (WTI) Local refining markets Rail to all coastal markets (Brent, LLS, WTI) N D 4Q 205 7

San Juan Overview ~226,000 net acres Oil window: ~96,000 acres Gas window: ~30,000 acres Currently operating rig ~3,900 total gross drilling locations 2 Oil window: ~400 3 Gas window: ~3,500 2 DRY GAS Commodity mix Oil window Oil: 52% NGLs: 9% Gas: 29% Gas window Natural gas: 99% NGLs: % OIL WET GAS Available sales outlets Oil: Local refining markets or rail (WTI, Brent, LLS) Gas: Blanco Hub Acreage owned or controlled by WPX 2 Includes non-op and operated locations 3 Assumes 4,600' laterals 8

Domestic Price Realization for 205 Oil ($/bbl) Gas ($/Mcf) NGL ($/bbl) Q 5 2Q 5 3Q 5 4Q 5 Q 5 2Q 5 3Q 5 4Q 5 Q 5 2Q 5 3Q 5 4Q 5 Weighted-Average Sales Price $38.34 $49.64 $40.0 $35.4 $2.90 $2.40 $2.69 $2.25 $22.74 $20.40 $7.87 $6.82 Revenue Adjustments $(.70) $(.04) $(.99) $(.3) $(.28) $(.32) $(.30) $(.26) $(7.34) $(6.64) $(5.47) $(4.90) Net Price 2 $37.64 $48.60 $38. $35.0 $2.62 $2.08 $2.39 $.99 $5.40 $3.76 $2.40 $.92 Realized Portion of Derivatives Not Designated as Hedges 3 $29.49 $24.92 $3.79 $32.76 $.05 $.02 $0.9 $.23 -- - Net Price Including All Derivatives $67.3 $73.52 $69.90 $67.86 $3.67 $3.0 $3.30 $3.22 $5.40 $3.76 $2.40 $.92 Natural gas revenue adjustments are primarily related to field compression fuel. NGL revenue adjustments include T&F and revenue sharing. Of the oil revenue adjustments, gathering deductions represent $(.33). 2 Net Price equals income statement product revenues by commodity, divided by volume. 3 Represents the realized cash flows that occurred during each quarter, which are attributable to derivatives that were not designated as hedges for accounting purposes. 9

205 Production by Basin First Quarter Second Quarter Third Quarter Fourth Quarter Year to Date Oil Gas NGL Total Oil Gas NGL Total Oil Gas NGL Total Oil Gas NGL Total Oil Gas NGL Total MBbls Mmcf MBbls MBOE MBbls Mmcf MBbls MBOE MBbls Mmcf MBbls MBOE MBbls Mmcf MBbls MBOE MBbls Mmcf MBbls MBOE Permian - - - - - - - - 4.6 8.6.6 9.3 9. 27.3 2.8 6.5 3.5.6. 6.5 Williston 24.9 2.6.8 28.8 22.6 2.4 2.0 26.6 8.9 0. 2. 22.7 20.9.9.9 24.8 2.8.7 2.0 25.7 San Juan 8. 7.7 2.3 30.0 8.5 25.6 3. 32.6 0.4 3.4 4. 36.4 8.6 4. 4. 36.3 8.9 29.0 3.4 33.8 Piceance.6 529.4 2.7 02.5.6 50.7 4.4 0..3 480.9 3.3 94.7.4 465.6 3.0 92.0.5 496.4 3.4 97.6 Other 0.0 45.6 0. 7.8 0.0 25.9 0.2 4.5 0.0 23.6 0.2 4.2 0.0 2.3 0.2 3.5 0.0 29. 0. 5.0 Total Continuing 34.6 705.3 6.9 69. 32.7 674.6 9.7 64.8 35.2 664.6 2.3 67.3 40.0 667.2 22.0 73. 35.6 677.8 20.0 68.6 20

Permian: Infrastructure Capacity in Place for Rapid Development Water gathering system 74 miles of pipeline 200,000 barrels per day of capacity Current utilization: ~90,000 bpd Fresh water transfer system 6 miles of pipeline Supports temporary system to D&C new wells Significantly reduces well costs Gas gathering system 92 miles of pipeline 90 MMcf/d of gas compression capacity Current utilization : ~40 MMcf/d Full field accessibility to electrical power Opportunity to improve netbacks with future oil gathering build out Owned and operated Future Oil Gathering Pipeline Fresh Water Pipeline Gas Gathering Pipeline Produced Water Disposal RKI Leasehold 2

Non-GAAP

WPX Non-GAAP Disclaimer This presentation may include certain financial measures, including adjusted EBITDAX (earnings before interest, taxes, depreciation, depletion, amortization and exploration expenses), that are non-gaap financial measures as defined under the rules of the Securities and Exchange Commission. This presentation is accompanied by a reconciliation of these non-gaap financial measures to their nearest GAAP financial measures. Management uses these financial measures because they are widely accepted financial indicators used by investors to compare a company s performance. Management believes that these measures provide investors an enhanced perspective of the operating performance of the company and aid investor understanding. Management also believes that these non-gaap measures provide useful information regarding our ability to meet future debt service, capital expenditures and working capital requirements. These non-gaap financial measures should not be considered in isolation or as substitutes for a measure of performance prepared in accordance with United States generally accepted accounting principles. 23

Reconciliation-Adjusted Income (Loss) from Continuing Operations (Unaudited) 204 205 (Dollars in millions, except per share amounts) Q 2Q 3Q 4Q YTD Q 2Q 3Q 4Q YTD Income (loss) from continuing operations attributable to WPX Energy, Inc. available to common stockholders $ - $ (44) $ 46 $ 227 $ 29 $ 22 $ (23) $ (0) $ (,537) $ (,648) Income (loss) from continuing operations - diluted earnings per share $ - $(0.7) $ 0.23 $.0 $ 0.62 $ 0. $ (0.2) $(0.44) $(5.58) $ (7.04) Pre-tax adjustments: Impairment of producing properties and equity investment $ - $ - $ - $ 20 $ 20 $ - $ - $ - $2,3 $2,3 Impairments- exploratory related $ - $ 40 $ 22 $ 67 $ 29 $ - $ - $ 47 $ 29 $ 76 Net (gain) loss on sales of assets $ - $ 95 $ $ - $ 96 $ (69) $ (209) $ (2) $ (70) $ (350) Expense related to Early Exit Program $ - $ 2 $ 8 $ - $ 0 $ - $ - $ - $ - $ - Contract termination and early rig release expenses $ - $ - $ 6 $ 6 $ 2 $ 26 $ - $ - $ 5 $ 3 Accrual for certain future gathering obligations associated with an abandoned area $ - $ - $ - $ - $ - $ - $ - $ - $ 23 $ 23 Assignment of natural gas storage commitment $ - $ - $ - $ 4 $ 4 $ - $ - $ - $ - $ - Costs related to severance and relocation $ - $ - $ - $ - $ - $ 8 $ 7 $ $ () $ 5 Costs related to acquisition and retention $ - $ - $ - $ - $ - $ - $ $ 03 $ $ 05 Unrealized MTM (gain) loss $ 27 $ - $ (33) $ (453) $ (559) $ 30 $ 203 $ (50) $ 6 $ 99 Total pre-tax adjustments $ 27 $ 237 $ (96) $ (346) $ (78) $ (5) $ 2 $ 99 $2,34 $2,40 Less tax effect for above items $ (0) $ (87) $ 35 $ 26 $ 64 $ 2 $ () $ (35) $ (852) $ (886) Impact of state deferred tax rate change $ - $ - $ - $ - $ - $ - $ - $ - $ 8 $ 8 Impact of new state tax law in New York (net of federal benefit) $ 9 $ - $ - $ - $ 9 $ - $ - $ - $ - $ - Total adjustments, after-tax $ 26 $ 50 $ (6) $ (220) $ (05) $ (3) $ $ 64 $,470 $,532 Adjusted income (loss) from continuing operations available to common stockholders $ 26 $ 6 $ (5) $ 7 $ 24 $ 9 $ (22) $ (46) $ (67) $ (6) Adjusted diluted earnings (loss) per common share $ 0.3 $ 0.03 $(0.07) $ 0.03 $ 0.2 $ 0.09 $ (0.) $(0.8) $(0.24) $ (0.50) Diluted weighted-average shares (millions) 205.2 202.7 207.5 206.3 206.3 205.9 205.0 25.2 275.4 234.2 24

Reconciliation EBITDAX (Unaudited) 204 205 (Dollars in millions) Q 2Q 3Q 4Q YTD Q 2Q 3Q 4Q YTD Adjusted EBITDAX Reconciliation to net income (loss): Net income (loss) $ 9 $ (33) $ 66 $ 29 $ 7 $ 68 $ (30) $ (230) $ (,534) $ (,726) Interest expense 29 28 3 35 23 33 32 65 57 87 Provision (benefit) for income taxes 3 (82) 25 9 75 3 (4) (52) (862) (95) Depreciation, depletion and amortization 93 202 20 24 80 26 227 242 255 940 Exploration expenses 5 54 28 76 73 7 6 56 42 EBITDAX 269 69 35 663,352 337 22 8 (2,042) (,403) Impairment of producing properties and equity investment - - - 20 20 - - - 2,3 2,3 Accrual for certain future gathering obligations associated with an abandoned area - - - - - - - - 23 23 Net (gains) loss on sales of assets - 95-96 (69) (209) (2) (70) (350) RKI acquisition costs and loss on acquired debt retirement - - - - - - - 87-87 Net (gain) loss on derivatives 95 7 (48) (498) (434) (05) 7 (205) (79) (48) Net cash received (paid) related to settlement of derivatives (68) (7) 5 45 (25) 35 32 55 95 67 (Income) loss from discontinued operations (9) () (20) 8 (42) (46) 7 24 2 87 Adjusted EBITDAX $ 277 $ 253 $ 99 $ 238 $ 967 $ 252 $ 222 $ 240 $ 240 $ 954 25

Disclaimer The information contained in this summary has been prepared to assist you in making your own evaluation of the Company and does not purport to contain all of the information you may consider important in deciding whether to invest in shares of the Company s common stock. In all cases, it is your obligation to conduct your own due diligence. All information contained herein, including any estimates or projections, is based upon information provided by the Company. Any estimates or projections with respect to future performance have been provided to assist you in your evaluation but should not be relied upon as an accurate representation of future results. No persons have been authorized to make any representations other than those contained in this summary, and if given or made, such representations should not be considered as authorized. Certain statements, estimates and financial information contained in this summary constitute forward-looking statements or information. Such forward-looking statements or information involve known and unknown risks and uncertainties that could cause actual events or results to differ materially from the results implied or expressed in such forward-looking statements or information. While presented with numerical specificity, certain forward-looking statements or information are based () upon assumptions that are inherently subject to significant business, economic, regulatory, environmental, seasonal, competitive uncertainties, contingencies and risks including, without limitation, the ability to obtain debt and equity financings, capital costs, construction costs, well production performance, operating costs, commodity pricing, differentials, royalty structures, field upgrading technology, and other known and unknown risks, all of which are difficult to predict and many of which are beyond the Company's control, and (2) upon assumptions with respect to future business decisions that are subject to change. There can be no assurance that the results implied or expressed in such forward-looking statements or information or the underlying assumptions will be realized and that actual results of operations or future events will not be materially different from the results implied or expressed in such forward-looking statements or information. Under no circumstances should the inclusion of the forward-looking statements or information be regarded as a representation, undertaking, warranty or prediction by the Company or any other person with respect to the accuracy thereof or the accuracy of the underlying assumptions, or that the Company will achieve or is likely to achieve any particular results. The forward-looking statements or information are made as of the date hereof and the Company disclaims any intent or obligation to update publicly or to revise any of the forward-looking statements or information, whether as a result of new information, future events or otherwise. Recipients are cautioned that forward-looking statements or information are not guarantees of future performance and, accordingly, recipients are expressly cautioned not to put undue reliance on forward-looking statements or information due to the inherent uncertainty therein. 26

Reserves Disclaimer The SEC requires oil and gas companies, in filings made with the SEC, to disclose proved reserves, which are those quantities of oil and 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, under existing economic conditions, operating methods, and governmental regulations. The SEC permits the optional disclosure of probable and possible reserves. We have elected to use in this presentation probable reserves and possible reserves, excluding their valuation. The SEC defines probable reserves as those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. The SEC defines possible reserves as those additional reserves that are less certain to be recovered than probable reserves. The Company has applied these definitions in estimating probable and possible reserves. Statements of reserves are only estimates and may not correspond to the ultimate quantities of oil and gas recovered. Any reserve estimates provided in this presentation that are not specifically designated as being estimates of proved reserves may include estimated reserves not necessarily calculated in accordance with, or contemplated by, the SEC s reserves reporting guidelines. Investors are urged to consider closely the disclosure regarding our business that may be accessed through the SEC s website at www.sec.gov. The SEC s rules prohibit us from filing resource estimates. Our resource estimations include estimates of hydrocarbon quantities for (i) new areas for which we do not have sufficient information to date to classify as proved, probable or even possible reserves, (ii) other areas to take into account the low level of certainty of recovery of the resources and (iii) uneconomic proved, probable or possible reserves. Resource estimates do not take into account the certainty of resource recovery and are therefore not indicative of the expected future recovery and should not be relied upon. Resource estimates might never be recovered and are contingent on exploration success, technical improvements in drilling access, commerciality and other factors. 27