1 st Quarter 2016 Earnings Call

Transcription

1 1 st Quarter 2016 Earnings Call Rick Muncrief, President and CEO May 5, 2016

2 Recent Highlights CLOSED SAN JUAN MIDSTREAM SALE CLOSED PICEANCE SALE AMENDED CREDIT FACILITY ~$1.2B IN COMPLETED ASSETS SALES 2016 FLEXIBLE CAPITAL PROGRAM REPURCHASED ~$185MM of 2017 DEBT MATURITY STRONG LIQUIDITY POSITION PROVIDES OPTIONALITY ~80% OIL PRODUCTION HEDGED IN $60.35 WTI TECHNICAL LEADERSHIP PAYING DIVIDENDS WOLFCAMP A VISION WELL $5.0 MM 1 WITH 1,000 MBOE EUR 1 Including drilling, completions, facilities and artificial lift 2

3 Foundation in Place for Enhancing Value WORLD-CLASS ASSET BASE OPERATIONAL & TECHNICAL FOCUS PROVEN TRACK RECORD OF EXECUTION EXPERIENCED MANAGEMENT TEAM 3

4 Operations Update Clay Gaspar, Chief Operating Officer

5 2 5, F T. CULBERSON COUNTY REEEVES COUNTY REEEVES COUNTY LOVING COUNTY LOVING COUNTY WINKLER COUNTY WINKLER COUNTY ECTOR COUNTY ECTOR COUNTY MIDLAND COUNTY MIDLAND COUNTY GLASSCOCK COUNTY GLASSCOCK COUNTY HOWARD COUNTY WPX Acreage in the Heart of the Delaware DELAWARE BASIN WPX CENTRAL BASIN PLATFORM MIDLAND BASIN GUADALUPE PEAK WEST EAST DELAWARE SANDS BONE SPRING WOLFCAMP Map sourced from the West Texas Geological Society (1984) 5

6 Cumulative MBOE Wolfcamp A: Wells Trending Near Vision WOLFCAMP A WELLS LESS THAN 30 DAYS GEN GEN GEN 3 BASIN HIGHLIGHTS Completing generation 4 wells and LESS THAN 30 DAYS currently designing 5 and 6 0 Current EUR 900 MBOE Current total well cost $5.3MM Normalized Days On Production Drilling: $2.7MM Completions: $2.0MM Facilities & Artificial Lift: $0.6MM VISION 1,000 MBOE 2016 GUIDANCE 850 MBOE ACQUISITION 670 MBOE GEN 3 COMPLETIONS GEN 2 COMPLETIONS GEN 1 COMPLETIONS 6

7 B-tax ROR EUR, MBOE Wolfcamp A: Highly Economic at Today s Commodity Price 130% 120% 110% 100% PRICE SENSITIVITY CURVE VISION: $5.0MM WELL COST- 1,000 MBOE CURRENT: $5.3MM WELL COST- 900 MBOE 2016 GUIDANCE: $6.0MM WELL COST- 850MBOE 1,300 1,200 CAPITAL/EUR SENSITIVITY CURVE 3-Year AVG Price 2 $49.01 Oil and $2.87 Gas 90% 80% 70% 60% 50% 40% 30% 20% 10% 0% 3-Year AVG Price 2 $49.01 Oil and $2.87 Gas $40.00 $50.00 $60.00 $70.00 Flat WTI Oil Price 1,100 1, Vision VISION Current 2016 Guidance CURRENT 2016 GUIDANCE $4.0 $4.5 $5.0 $5.5 $6.0 $6.5 $7.0 Total Well Cost ($MM) Lateral Length: Current 4,800ft Current Total Well Cost: $5.3MM EUR: Current 900 MBOE B-Factor: 1.3 Crude Differential: $3.50 GP&T per BOE: $0.00 LOE per BOE: $6.75 Avg Working Interest 1 : 98% NRI 1 : 75% Indicates rate of return 2016 ASSUMPTIONS WOLFCAMP A WELL: COMMODITY MIX Oil Gas NGLs 25% 20% 55% 1 Based on 2016 Guidance 2 As of April 28,

8 Potential for Increasing EURs and Locations vs. Acquisition Assumption TOP WOLFCAMP X/Y WOLFCAMP X/Y X/Y PROVEN PRODUCTIVE IN WPX S STATELINE ACREAGE ~750 MBOE AVERAGE EUR FOR WELLS WITH ~2 YEARS OF PRODUCTION 1 UPPER AND LOWER WOLFCAMP A PROVEN PRODUCTIVE ~60MM BARRELS OF OIL POTENTIAL IN WOLFCAMP A PER 640 SECTION TOP WOLFCAMP A UPPER LANDING ZONE LOWER LANDING ZONE UPPER WOLFCAMP A ~850 MBOE AVERAGE EUR FOR WELLS WITH ~1 YEAR OF PRODUCTION 2 LOWER WOLFCAMP A ~1,000 MBOE AVERAGE EUR FOR WELLS WITH ~1 YEAR OF PRODUCTION 2 BASE WOLFCAMP A 8 PAY HYDROCARBONS 1 Based on EURs from 15 offset producer wells in Wolfcamp X/Y with an average of 2 years on production 2 Offset producer wells and RKI wells near Stateline, normalized 4800 lateral length LITHOLOGY POISSONS RATIO 8

9 Cumulative MBOE Williston: Results Validate Type Curve Increase Mandaree and Emma Owner Pad LESS THAN 30 DAYS BASIN HIGHLIGHTS Increasing type curve to 850 MBOE EUR Record 18.8 days for 3-mile lateral LESS THAN 30 DAYS Current total well cost $5.9MM Drilling: $2.3MM Completions: $2.6MM Facilities & Artificial Lift: $1.0MM Vision well 850 MBOE EUR $5.5MM total well cost Normalized Days on Production CURRENT/VISION 850 MBOE 2016 GUIDANCE 750 MBOE EMMA OWNER PAD MANDAREE PAD 1 Spud to rig release 9

10 B-tax ROR EUR,MBOE Williston: Highly Economic at Today s Commodity Price 150% 140% 130% 120% 110% 100% 90% 80% 70% 60% 50% 40% 30% 20% 3-Year AVG Price 2 10% $49.01 Oil and $2.87 Gas 0% $40.00 $50.00 $60.00 $70.00 Flat WTI Oil Price Lateral Length: 9,600 ft. Current Total Well Cost: $5.9MM EUR: 850 MBOE B-Factor: 1.6 Differential 1 : ~$8.00 GP&T per BOE 3 : $1.05 LOE per BOE: $5.10 Avg Working Interest 4 : 83.5% NRI 4 : 66.4% Indicates rate of return PRICE SENSITIVITY CURVE VISION: $5.5MM WELL COST- 850 MBOE CURRENT: $5.9MM WELL COST- 850 MBOE 2016 GUIDANCE: $7.1MM WELL COST- 750MBOE 1, $4.5 $5.0 $5.5 $6.0 $6.5 $7.0 $7.5 Oil Gas NGLs CAPITAL/EUR SENSITIVITY CURVE 3-Year AVG Price 2 $49.01 Oil and $2.87 Gas VISION Total Well Cost ($MM) 2016 ASSUMPTIONS WILLISTON WELL: COMMODITY MIX 10% CURRENT 10% 80% 2016 GUIDANCE 1 Wellhead differential of $5.15 and $2.85 of GP&T accounted for as a contra revenue 2 As of April 28, Excludes GP&T contra revenue 4 Based on 2016 Guidance 10

11 Cost per Lateral Foot Well Cost/120 Day BO Cost per Lateral Foot Well Cost/120 Day BO WPX Demonstrating Operational Excellence $1,600 $1,400 $1,200 $1,000 $800 $600 $400 $1,100 $1,000 $900 $800 $700 $600 $500 $400 A B WPX 4Q 15 I EARLY WPX $4 $5 $6 $7 $8 $9 A DOING MORE FOR LESS PERMIAN COST PER LATERAL FOOT WPX VISION WPX 2016 C B CBR AREA C F E D $5 $6 $7 $8 $9 $10 G Well Cost ($MM) WILLISTON COST PER LATERAL FOOT F E D G WPX 4Q 15 H Well Cost ($MM) I H Q 1 J J Q 2 $130 $120 $110 $100 $90 $80 $70 $60 $50 $165 $145 $125 $105 PERMIAN COST PER BARREL OF OIL (120 DAY CUM) WPX VISION CBR AREA EARLY WPX $4 $5 $6 $7 $8 $9 A A GETTING MORE FOR LESS B B F C E D D E F I WPX 4Q 15 G H $85 C WPX $65 WPX 4Q $45 $5 $6 $7 $8 $9 $10 I G Well Cost ($MM) WILLISTON COST PER BARREL OF OIL (120 DAY CUM) Well Cost ($MM) H J J Data sourced from IHS and 4Q 15 company presentations Permian peer group includes: APC, MTDR, FANG, CPE, EOG, EGN, XEC, APA, OXY, DVN Williston peer group includes: CLR, ERF, EOG, HK, HESS, MRO, OAS, QEP, SM, WLL 11

12 Cumulative MBOE San Juan Gallup: Organic Growth and Value Creation Mancos Gallup Well Performance LESS LESS THAN THAN DAYS DAYS Current total well cost $4.1MM 1 BASIN HIGHLIGHTS Drilling: $1.3MM Completions: $2.3MM Facilities & Artificial Lift: $0.5MM Drilling record of 7.5 days for 1.5 mile lateral LESS THAN 30 DAYS Normalized Days on Production 21% reduction in LOE 2,3 39% improvement in oil differentials 3 CURRENT 650 MBOE 2016 GUIDANCE 465 MBOE LESS THAN 45 DAYS PRODUCTION GREATER THAN 45 DAYS PRODUCTION West Lybrook 6-well pad 1st sales expected July Assumes 1 ½ mile laterals. 2 LOE per BOE based on total operations for San Juan Basin 3 1Q 2015 vs. 1Q

13 Financial Update Kevin Vann, Chief Financial Officer

14 1st Quarter Results Dollars in millions, except production numbers 1Q Average Daily Production Oil (Mbbl/d) Gas (MMcf/d) NGLs (Mbbl/d) Equivalent (MBOE/d) Adjusted EBITDAX Adjusted Net Income (Loss) from Continuing Operations Available to Common Shareholders (58) 49 Capital Expenditures/Activity Note: Adjusted EBITDAX and adjusted net income are non-gaap measures. A reconciliation to relevant measures included in GAAP is provided in this presentation. 1 Capex includes expenditures for discontinued operations 14

15 $MM 2017 % of Production Hedged WPX Liquidity, Hedges and Debt Maturities STRONG HEDGE POSITION Total Liquidity (as of 5/3/2016) Cash and Equivalents $583 Available Revolver Capacity 1,025 Total Liquidity $1.6B 100% 80% 60% 40% 20% $60.35 $3.93 0% Oil Natural Gas ~80% of oil production hedged Oil: 22,804 bbl/d Hedged $60.35 per barrel Natural gas fully hedged $3.93 per MMBtu $50.71 per barrel Gas: 90,000 mmbtu/d $2.82 per MMBtu Debt Maturity $1,200 $1,000 $800 $600 $400 $200 $0 Expect $1.2B OF SALES PROCEEDS IN 1H OF 2016 $217 $1,485 UNDRAWN $500 $1,100 $500 $ Senior Notes Senior Notes Senior Notes Senior Notes Senior Notes 1 Based on midpoint of guidance 15

16 Execution Core to WPX PORTFOLIO REBALANCED IN CORE BASINS ENCOURAGING RESULTS IN EACH ASSET WORLD-CLASS ROCK IN DELAWARE BASIN ADDITIONAL UPSIDE IN WOLFCAMP REMAINING OPPORTUNISTIC WPX is working from a position of strength; core assets, proven execution, and strong liquidity 16

17 Appendix

18 2016 Full-Year Guidance (Excludes Piceance) Production FY16 Oil Mbbl/d Natural Gas MMcf/d NGL Mbbl/d Total MBOE/d Cap Ex ($ in Millions) FY16 Delaware $ Williston San Juan Total D&C Capital $ Other Total 2 $350 - $450 Avg. Price Differentials 3 FY16 Oil WTI per barrel ($5.00) - ($7.00) NYMEX Nat. Gas (Mcf) ($0.40) - ($0.60) Expenses FY16 $ per BOE LOE $ $6.25 GP&T Production Tax Cash Operating Expense $ $11.50 DD&A $ in Millions G&A 5 $165 - $185 Marketing 0-25 Exploration Interest Expense ASSUMPTIONS $40.00 WTI $2.00 NYMEX RIGS ~3 DELAWARE ~1 WILLISTON ~1 SAN JUAN OIL EXIT RATE 6 Flat 4Q 15 vs. 4Q 16 Net Realized Price 4 FY16 Tax Rate FY16 NGL % of WTI 23% - 28% Tax Provision 33% - 37% 1 Other includes expenditures for Other Basins, Land, Exploration and Corporate. 2 Excludes any acquisition capital. 3 Average price differentials ranges for oil and natural gas exclude hedges, but include basis differential and revenue adjustments. 4 Percentage of realized price ranges for NGLs excludes hedges, but includes basis differential and revenue adjustments. 5 Excludes one-time charges for severance and relocation costs and includes stock compensation expenses of $25MM $30MM. 6 Adjusted for the 1.4M barrels of oil produced in the Piceance in 4Q 15. Also, assumes the high-end of the D&C capital range. G&A RUN RATE ANNUALIZED RUN RATE OF $150MM BY 4Q 16 18

19 WPX Hedges Updated: April 29, Q 4Q Volume/Day Average Price Volume/Day Average Price Crude Oil (bbl) Fixed Price Swaps¹ 30,438 $ ,804 $50.71 Crude Oil Basis (bbl) Midland Basis Swaps 5,000 ($0.45) - - Natural Gas (MMBtu) Fixed Price Swaps 1 146,541 $ ,000 $2.82 Natural Gas Basis (MMBtu) MidCon Basis Swaps 5,000 ($0.23) - - Rockies Basis Swaps 32,727 ($0.33) - - San Juan Basis Swaps 100,000 ($0.18) 32,500 ($0.16) SoCal Basis Swaps 45,000 ($0.01) 10,000 $0.00 Permian Basis Swaps 32,500 ($0.17) In connection with several natural gas and crude oil swaps, we entered into call options and 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 calls and swaptions for the balance of 2016 total 2,099 bbl/d at a weighted average strike price of $52.69 and 1,673 bbl/d at a weighted average strike price of $57.15, respectively. Natural gas calls and swaptions for 2017 total 16,301 MMBtu/d at a weighted average strike price of $4.50 and 65,000 MMBtu/d at a weighted average strike price of $4.19, respectively. Crude oil calls and swaptions for 2017 total 2,000 bbl/d at a weighted average strike price of $57.10 and 3,264 bbl/d at a weighted average strike price of $51.22, respectively. Natural gas calls for 2018 total 16,301 MMBtu/d at a weighted average strike price of $4.75. Crude oil calls for 2018 total 2,000 bbl/d at a weighted average strike price of $

20 Delaware Overview ~94,000 net acres 1 Currently operating ~2 rigs 3,600 gross risked locations Commodity mix 2 54% oil 29% natural gas 17% NGLs Available sales outlets Holley Frontier s Artesia, NM Refinery Western s El Paso Refinery Gulf Coast Cushing Midland Information based on YE Includes ~1,000 acres in Midland Basin 2 Based on ~YE15 Production 20

21 9,000 Overview of WPX s World-Class Delaware Position ~94,000 TOTAL NET ACRES 1, ~60,000 NET ACRES NEAR STATELINE WOLFCAMP BELL CANYON CHERRY CANYON 12 PROSPECTIVE ZONES WITH 3,600++ GROSS LOCATIONS AVALON DELAWARE SANDS BRUSHY CANYON AVALON OWNED/OPERATED MIDSTREAM INFRASTRUCTURE FIRST BONE SPRING SECOND BONE SPRING 1.1+ BILLION BARRELS OF EQUIVALENT NET RESOURCE POTENTIAL BONE SPRING THIRD BONE SPRING WOLFCAMP A WOLFCAMP B WOLFCAMP C WOLFCAMP D WPX OPERATED ACREAGE 1 Includes ~1,000 acres in Midland Basin NON-OPERATED ACREAGE Hydrocarbon Pay Indication 21

22 Wolfcamp X/Y Present in Stateline Acreage 5 EDDY 6 LEA ANDREWS 7 WOLFCAMP X/Y LOCATIONS Well Name 6 Mo CUM LL #/ft EUR MBOE Oil % 1 JOHNSON 44-02S-B53 WF 204H ,621 2, % 2 DOROTHY WHITE 82-TTT-B33 WF 1H ,866 1, % LOVING 9 WINKLER 3 BARNETT 90-TTT-B01 WF 201H ,376 2,024 4 NORTON-SCHAUB 84-TTT-B33 WF 1H ,727 2, % 5 GUITAR 10 24S 28E RB 202H ,232 1, % 6 TIGER 14 24S 28E RB 204H ,656 2,002 7 RUBY 2 STATE COM 701H ,494 1, % 8 BURT BILLY 90-TTT-B33 WF 203H 96.9 ~8,200 9 COPPERHEAD H , % REEVES WPX ACREAGE X/Y LOCATIONS 10 UNIVERSITY H % Operators include MTDR, EGN, and EOG 22

23 BOE/D Cum MBOE BOE/D Cum MBOE BOE/D Cum MBOE Type Curve Assumptions: San Juan Gallup, Williston, and Wolfcamp A Type Curve: Wolfcamp A Type Curve: San Juan Gallup Type Curve: Williston 1, , ,500 1,250 1,200 1, , Yrs ,000 1,500 1, , Years Years Years 0 BOE/D CUM MBOE BOE/D CUM MBOE BOE/D CUM MBOE Wolfcamp A Assumptions San Juan Gallup Assumptions Williston Assumptions Lateral Length: 4,800 ft. Total Well Cost: $5.3MM EUR: 900 MBOE B-Factor: 1.3 Oil Differential: $3.50 GP&T per BOE: $0.00 LOE per BOE: $6.75 Avg Working Interest 3 : 98% NRI 3 : 75% Lateral Length: 1.5 Mile Total Well Cost: $4.1MM EUR: 650 MBOE B-Factor: 1.4 Oil Differential: ~$8.00 GP&T per BOE: $3.75 LOE per BOE: ~$6.50 Avg Working Interest 3 : 96.28% NRI 3 : 77.77% Lateral Length: 9,600 ft. Total Well Cost: $5.9MM EUR: 850 MBOE B-Factor: 1.6 Oil Differential 1 : ~$8.00 GP&T per BOE 2 : $1.05 LOE per BOE: $5.10 Avg Working Interest 3 : 83.5% NRI 3 : 66.4% 1 Wellhead differential of $5.15 and $2.85 of GP&T accounted for as a contra revenue 2 Excludes GP&T contra revenue 3 Based on 2016 Guidance 23

24 Permian: Infrastructure Capacity in Place for Rapid Development Water gathering system 174 miles of pipeline 200,000 barrels per day of capacity Current utilization: ~90,000 bpd Fresh water transfer system 16 miles of pipeline Supports temporary system to D&C new wells Significantly reduces well costs Gas gathering system 192 miles of pipeline 90 MMcf/d of gas compression capacity Current utilization : ~50 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 24

25 Williston Overview ~85,000 net acres Currently operating ~1 rig 575+ gross drilling locations ~510 operated drilling locations ~70 non-op locations Commodity mix 1 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 Information based on YE Based on YE15 Production 25

26 San Juan Overview ~226,000 net acres Oil window: ~96,000 acres 1 Gas window: ~130,000 acres Currently operating ~1 rig ~3,900 total gross drilling locations 2 Oil window: ~400 3 Gas window: ~3,500 2 Commodity mix 4 Oil window Oil: 52% NGLs: 19% Gas: 29% Gas window Natural gas: 99% NGLs: 1% OIL WET GAS DRY GAS Available sales outlets Oil: Local refining markets or rail (WTI, Brent, LLS) Gas: Blanco Hub Information based on YE Acreage owned or controlled by WPX 2 Includes non-op and operated locations 3 Assumes 4,600' laterals 4 Based on YE15 Production 26

27 Non-GAAP

28 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. 28

29 Reconciliation-Adjusted Income (Loss) from Continuing Operations (Unaudited) (Dollars in millions, except per share amounts) 1Q 2Q 3Q 4Q YTD 1Q 2Q 3Q 4Q YTD Income (loss) from continuing operations attributable to WPX Energy, Inc. available to common stockholders $ 52 $ 23 $ (74) $ (24) $ (23) $ (5) $ (5) Income (loss) from continuing operations - diluted earnings per share $ 0.25 $ 0.11 $(0.29) $(0.09) $(0.10) $ (0.02) $ (0.02) Pre-tax adjustments: Impairments- exploratory related $ - $ - $ 47 $ 3 $ 50 $ - $ - Net (gain) loss on sales of assets $ (69) $ (208) $ (2) $ (70) $ (349) $ (198) $ (198) Contract termination and early rig release expenses $ 26 $ - $ - $ 5 $ 31 $ - $ - Accrual for certain future gathering obligations associated with an abandoned area $ - $ - $ - $ 23 $ 23 $ - $ - Costs related to severance and relocation $ 8 $ 7 $ 1 $ (1) $ 15 $ 3 $ 3 Costs related to acquisition (including loss on acquired debt extinguishment) $ - $ 1 $ 103 $ 1 $ 105 $ - $ - Previously capitalized costs expensed following credit facility amendment $ - $ - $ - $ - $ - $ 4 $ 4 Gain on retirement of debt $ - $ - $ - $ - $ - $ (3) $ (3) Unrealized MTM (gain) loss $ 30 $ 203 $ (50) $ 16 $ 199 $ 76 $ 76 Total pre-tax adjustments $ (5) $ 3 $ 99 $ (23) $ 74 $ (118) $ (118) Less tax effect for above items $ 2 $ (1) $ (35) $ 7 $ (27) $ 43 $ 43 Impact of state deferred tax rate change $ - $ - $ - $ 8 $ 8 $ 14 $ 14 Impact of state valuation allowance $ - $ - $ - $ - $ - $ 8 $ 8 Total adjustments, after-tax $ (3) $ 2 $ 64 $ (8) $ 55 $ (53) $ (53) Adjusted income (loss) from continuing operations available to common stockholders $ 49 $ 25 $ (10) $ (32) $ 32 $ (58) $ (58) Adjusted diluted earnings (loss) per common share $ 0.24 $ 0.12 $(0.04) $(0.11) $ 0.14 $ (0.21) $ (0.21) Diluted weighted-average shares (millions)

30 Reconciliation EBITDAX (Unaudited) (Dollars in millions) 1Q 2Q 3Q 4Q YTD 1Q 2Q 3Q 4Q YTD Adjusted EBITDAX Reconciliation to net income (loss): Net income (loss) $ 68 $ (30) $ (230) $ (1,534) $ (1,726) $ (12) $ (12) Interest expense Provision (benefit) for income taxes 29 1 (27) Depreciation, depletion and amortization Exploration expenses EBITDAX (1,278) (892) Accrual for certain future gathering obligations associated with an abandoned area Net (gains) loss on sales of assets (69) (208) (2) (70) (349) (198) (198) RKI acquisition costs and loss on extinguishment of acquired debt Net (gain) loss on derivatives (105) 71 (205) (179) (418) (57) (57) Net cash received (paid) related to settlement of derivatives (Income) loss from discontinued operations (16) ,515 1, Adjusted EBITDAX $ 199 $ 181 $ 195 $ 206 $ 781 $ 131 $

31 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 (1) 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. 31

32 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 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. 32