EX-99.2 3 h85685exv99w2.htm EX-99.2 exv99w2
Exhibit 99.2
Noble Energy Analyst Conference November 15, 2011

 

2 Forward-looking Statements and Non-GAAP Measures This presentation contains certain "forward-looking statements" within the meaning of the "safe harbor" provisions of the Private Securities Litigation Reform Act of 1995. Words such as "anticipates," "believes," "expects," "intends," "will," "should," "may," and similar expressions may be used to identify forward-looking statements. Forward-looking statements are not statements of historical fact and reflect Noble Energy's current views about future events. They include estimates of oil and natural gas reserves and resources, estimates of future production, assumptions regarding future oil and natural gas pricing, planned drilling activity, future results of operations, projected cash flow and liquidity, business strategy and other plans and objectives for future operations. No assurances can be given that the forward-looking statements contained in this presentation will occur as projected, and actual results may differ materially from those projected. Forward-looking statements are based on current expectations, estimates and assumptions that involve a number of risks and uncertainties that could cause actual results to differ materially from those projected. These risks include, without limitation, the volatility in commodity prices for crude oil and natural gas, the presence or recoverability of estimated reserves, the ability to replace reserves, environmental risks, drilling and operating risks, exploration and development risks, competition, government regulation or other actions, the ability of management to execute its plans to meet its goals and other risks inherent in Noble Energy's business that are discussed in its most recent Form 10-K and in other reports on file with the Securities and Exchange Commission. These reports are also available from Noble Energy's offices or website, http://www.nobleenergyinc.com. Forward-looking statements are based on the estimates and opinions of management at the time the statements are made. Noble Energy does not assume any obligation to update forward-looking statements should circumstances or management's estimates or opinions change. This presentation also contains certain historical and forward-looking non-GAAP measures of financial performance that management believes are good tools for internal use and the investment community in evaluating Noble Energy's overall financial performance. These non-GAAP measures are broadly used to value and compare companies in the crude oil and natural gas industry. Please also see the Appendix to this presentation and Noble Energy's website at http://www.nobleenergyinc.com under "Investors" for reconciliations of the differences between any historical non-GAAP measures used in this presentation and the most directly comparable GAAP financial measures. The GAAP measures most comparable to the forward-looking non-GAAP financial measures are not accessible on a forward- looking basis and reconciling information is not available without unreasonable effort. The Securities and Exchange Commission requires oil and gas companies, in their filings with the SEC, to disclose proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. The SEC permits the optional disclosure of probable and possible reserves, however, we have not disclosed our probable and possible reserves in our filings with the SEC. We use certain terms in this presentation, such as "gross mean resources" and "unrisked resource potential." These estimates are by their nature more speculative than estimates of proved, probable and possible reserves and accordingly are subject to substantially greater risk of being actually realized. The SEC guidelines strictly prohibit us from including these estimates in filings with the SEC. Investors are urged to consider closely the disclosures and risk factors in our most recent Form 10-K and in other reports on file with the SEC, available from Noble Energy's offices or website, http://www.nobleenergyinc.com.

 

3 Agenda November 15 Analyst Conference Company Overview Chuck Davidson Chairman and CEO Operations Summary Dave Stover President and COO Financial Review Ken Fisher SVP and CFO DJ Basin Ted Brown SVP U.S. - Northern Region Marcellus John Lewis VP U.S. - Southern Region Break

 

4 Agenda November 15 Analyst Conference Gulf of Mexico John Lewis VP U.S. - Southern Region West Africa Rodney Cook SVP International Eastern Mediterranean Rodney Cook SVP International Exploration Susan Cunningham SVP Exploration Closing Remarks / Q&A Chuck Davidson

 

Overview Chuck Davidson Chairman and CEO

 

Noble Energy in 2011 Positioned for a decade of growth Five Core Areas All with Substantial Growth Each with double-digit production growth Proven reserves projected to increase 150% over 5 years Multiple Major Projects Coming on Stream Starting NOW! Large and Growing Portfolio of High Return Reinvestment Opportunities Diversified with net risked resources of 7.4 BBoe Sustainable Industry-leading Exploration Program Financial Capacity to Deliver Organizational Strength to Execute

 

Key Accomplishments Substantial progress in a short period 1/11 Aseng Online 270 MMBoe Reserves Add $3 B Liquidity 1st Deepwater GOM Permit (Santiago Disc.) Carla Discovery Alen Sanction 7/11 1/12 7/10 U.S. Onshore Deepwater GOM W. Africa E. Mediterranean Tamar Sanction Leviathan Discovery Accelerate Wattenberg Niobrara Non-core Asset Sales Marcellus JV

 

Leveraging Our Recent Accomplishments Five-year outlook even better than before Exploration Success and Marcellus Addition Providing New High-return Investment Opportunities 5-year capital investment increased from $13 B to $24 B Projected Production Growth Rate has Increased from 10% to 17% per Year Net Risked Resources have Grown 75% to 7.4 BBoe Projected 5-year reserve replacement has grown from 177% to 400% of production Better Portfolio Diversification Marcellus adds fifth core area and helps retain balance U.S. production growing to 66% in 2016 Further Strengthened Organizational Capabilities

 

Debt-adjusted* Growth per Share Dramatic progress in just one year * Terms defined in appendix Compound Annual Growth Rate Reserves Production Cash Flow 2010 Analyst Day (2010 - 2015) 0.05 0.1 0.18 2011 Analyst Day (2011 - 2016) 0.0001 0.0001 0.0001 Reserves per Share Production per Share Cash Flow per Share 5% 10% 18%

 

Debt-adjusted* Growth per Share Dramatic progress in just one year * Terms defined in appendix Compound Annual Growth Rate Reserves Production Cash Flow 2010 Analyst Day (2010 - 2015) 0.05 0.1 0.18 2011 Analyst Day (2011 - 2016) 0.18 0.15 0.22 Reserves per Share Production per Share Cash Flow per Share 5% 18% 10% 15% 18% 22%

 

Key Outcomes by 2016 Superior operational and financial performance 17% CAGR to 490 MBoe/d 20% CAGR to 2.7 BBoe 5-Yr F&D of $10/Boe Production Reserves Transparent Growth Profile for the Next Decade $1.4 B Free Cash Flow* in 2016 Portfolio Flexibility BTax Cash Margin* Up 15% to $44/Boe ROACE 17% in 2016 Cash Flow Returns * Term defined in appendix

 

Conference Themes Depth and Quality of Opportunities Material in scale and scope Value of a Diversified Portfolio Retaining flexibility and balance Capacity and Capabilities of Organization Allowing Capture of Full Value Sustainability of Exploration Success Depth and quality of prospect inventory Transparency of Future Growth Projects identified and positioned to deliver through the next decade Robust Financial Framework

 

Operations Summary Dave Stover President and COO

 

2 Operating Strategy Focus on Five Core Operating Areas DJ Basin, Marcellus, Deepwater GOM, Eastern Mediterranean and West Africa Convert Discovered Resources to Production Excel on major project execution Accelerate U.S. onshore developments Test Significant Exploration Opportunities Build off successes in core areas Expand through new ventures Manage the Portfolio Divest non-core assets to maintain focus Acquire bolt-on assets in core areas

 

3 Environment, Health and Safety Initiatives Creating value through responsible leadership Global EHS Management System Local Stakeholders Engagement Deepwater Well Control Containment System Participant in Carbon Disclosure Project Comprehensive Water Management Strategy Secure reliable supply Increase recycle and reuse Participation in Hydraulic Fracturing Chemical Disclosure

 

4 Operational Highlights - U.S. DJ Basin Record well results De-risked Wattenberg horizontal program Accelerating activity levels Marcellus Results already better than expected Activity accelerating Prepared to operate Deepwater GOM Significant near-term production growth Gunflint appraisal proceeding Maturing exploration prospects

 

5 Operational Highlights - International West Africa Aseng on production with world-class project execution Alen development benefitting from Aseng experiences Testing exploration potential Eastern Mediterranean Tamar on schedule and on budget Appraisal of Leviathan discovery Gas commercialization progressing Remaining exploration potential New Ventures Prospects with potential to become new core areas

 

6 Proved Reserves* Risked Resources Unrisked Resources Proved Reserves 1159 1159 1159 Discovered Unbooked 3314 3613 Core Area Exploration 2192 5315 New Play Types 738 3897 14.0 7.4 1.2 Risked Net DJ Basin 1335 Marcellus 1253 Deepwater GOM 641 Eastern Med 2475 West Africa 632 Other 476 New Venture 591 * 2010 year-end plus ~400 Bcf for Marcellus acquisition Net Resources Over six times proved reserves Deepwater GOM Other Eastern Med DJ Basin Marcellus New Ventures West Africa

 

7 Net Risked Resource Substantial growth and de-risking in opportunity set 2008 2010 2011 Proved Reserves 880 870 1159 Discovered Unbooked 871 1318 3314 Core Area Exploration 1198 1995 2192 New Play Types 0 0 738 45% 2.9 7.4 4.2 75% Net Risked Resource (BBoe)

 

8 Net Risked Resource Changes Since 2010 High-quality investment opportunities Proved Proved2 Disc2 Disc Unbooked Core Area Expl New Play Types Other May-10 Resources 0.87 0 0 1.318 1.996 0 Leviathan 4.184 0 0 0 0 0.572 Wattenberg Niobrara 4.756 0 0 0 0.415 Marcellus JV 5.171 0 0 0 0 0 1.253 Other 6.424 1.019 Nov-11 Resources 1.159 0 0 3.314 2.031 0.939 0 Horizontal Niobrara De-risked Marcellus JV June 2010 Analyst Conference Leviathan Discovery New Ventures and Other Additions November 2011 Analyst Conference Net Risked Resources (BBoe) 4.2 7.4 1.0 1.3 0.4 0.6

 

9 Proved Reserves Outlook Increasing 150% over the next five years All-in Reserve Replacement* Proven track record over last 5 years Expecting performance to accelerate 177% 20% CAGR 1.1 2.7 Proved Reserves (BBoe) 400% * Term defined in appendix

 

10 Production Outlook Growth in all core areas 2011 2012 2013 2014 2015 2016 Base 198 165 115 91 83 78 Onshore Horizontal 9 35 72 118 163 196 Offshore Major Projects 12 24 49 76 87 150 Other Development 1 30 38 37 43 49 Exploration 1 1 2 5 9 15 17% CAGR MBoe/d Note: Non-core divestitures assumed effective 1/2013 Projected Annual Growth Rates (2011 - 2016) * Alba LNG gas excluded DJ Basin Marcellus DW GOM W Africa* E Med 0.15 0.37 0.32 0.15 0.2 15% 126% 32% 14% 20%

 

11 Onshore U.S. Divestments Results in highly concentrated operations Less than 10% of Global Portfolio 23 MBoe/d of current net production 88 MMBoe net proved reserves ~70% natural gas, 30% liquids Expect to conclude in 2012 Maintaining Focus on Core Areas Reallocating resources to areas where NBL has competitive advantages Redeploying capital to high-value, high-growth projects Gas Liquids

 

12 Volume Profile Maintaining diversified commodity exposure U.S. Contribution Increases from 53% to 66% US Gas Alba Intl Gas WTI Brent 29 15 17 20 19 U.S. Gas Intl Gas WTI 2011 US Gas Int'l Gas Alba Liquids 39 16 6 20 19 U.S. Gas Intl Gas WTI 2016 Brent, LLS Brent, LLS Alba LNG Gas Alba LNG Gas

 

13 Offshore Major Projects Ongoing Development Exploration Other Development East 6361 11280 4023 5034 Capital Investment Outlook Annual organic cash capital* grows from $3 to $5 B Onshore Horizontal Developments Offshore Major Projects Other Development Exploration 2011 2012 2013 2014 2015 2016 2.868 3.659 4.189 5.232 5.48 5.305 By Year * Term defined in appendix DJ Basin Deepwater GOM West Africa Eastern Med Other Marcellus Capex 8833 2584 3056 4086 2089 6025 DJ Basin West Africa Other Eastern Med Marcellus Deepwater GOM

 

14 Capital Changes Since 2010 Increases driven by success * Term defined in appendix 2010 Analyst Day Marcellus Niobrara Eastern Med Other 2011 Analyst Day Base 2587 4456 Spacer 2587 3601 4309 4455 Plus 746 708 439 Minus 293 Plus 2 268 Horizontal Niobrara De-risked Leviathan Discovery, Eastern Med. Exploration De-risked Carry 2.6 1.0 0.7 0.4 (0.2) 4.5 June 2010 Analyst Conference Marcellus JV Other November 2011 Analyst Conference Average Annual Organic Cash Capital* 2011 - 2016 ($B)

 

15 Major Development Project Line-up High value growth Bubble Size Represents Relative Full-cycle NPV Gas Oil LNG Predominant Product ... Year of First Significant Production

 

16 Keys to NBL's Success Executing Major Projects Leveraging learnings across all projects Clearly Defined Objectives Experienced and Empowered Project Teams Integration across disciplines Partnering with key contractors and suppliers Rigorous and Disciplined Project Management Practices Front-end loading Execution planning Performance management Real-time Global Learning Source: IPA $MM 80% 50% 75% of projects lower 90% of projects lower 10% of projects lower Actual X X 25% of projects lower Industry Subsea Cost Benchmark for West Africa Aseng Subsea Systems Aseng at Sanction

 

17 Major Project Impact Generates significant production and cash flow Projects Projected Net Impact in 2016 Production 340 MBoe/d Operating cash flow* $5 B Free cash flow* $1.6 B Self-funding Over Five Years 2011 2012 2013 2014 2015 2016 Offshore Investment 1.144 0 0.921 0 0.695 0 1.001 0 1.192 0 0.88 0 Onshore Investment 0.489 1.117 1.909 2.519 2.692 2.773 Offshore Operating Cash Flow 0.06 0.658 0.983 1.532 1.514 2.237 Onshore Operating Cash Flow 0.241 0.705 1.374 1.998 2.539 2.973 Net Production 8.7 16.4 30.9 58.2 74.1 94.4 120.2 141.2 165.9 194.9 211.1 228.7 247.4 275 306.1 340.3 Note: Offshore Projects includes Galapagos, Gunflint, Tamar, Leviathan, Aseng, Alen, Diega, and WA Gas Onshore includes 2011 forward development for horizontal Niobrara and Marcellus * See appendix for defined terms and reference price case.

 

18 Operations Summary Risked Resources Six Times Proved Reserves Project Execution on Track Reserves Projected to Increase 150% by 2016 Production Projected to More than Double Over the Next Five Years Portfolio Remains Well Balanced and Diversified

 

Financial Review Ken Fisher, SVP and CFO

 

2 Financial Imperatives Built capital structure to support business value creation Ensure Ability to Fund Attractive Opportunities Through the Commodity Cycle Long-cycle, long-life major projects Onshore horizontal programs Material organic exploration Proactively Manage Enterprise Risks Maintain Robust Metrics and Financial Flexibility Deliver Sustained Growth with Attractive Returns

 

3 Discretionary Cash Flow* Growth Projected 22% CAGR to 2016 2011 2012 2013 2014 2015 2016 DCF 2470 2922 3278 4038 4822 6708 $B * Term defined in appendix

 

4 Capital Structure Robust to ensure delivery of value Strong Liquidity... Robust to Commodity Price Cycle Conservative Balance Sheet and Investment Grade Rating Maintain Baa2 / BBB ratings Proactive Funding Strategy Cash on hand and operating cash flow Upsized credit facility Debt market funding Enterprise Risk Management Focus Commodity hedging program Risk ownership, matrices and mitigation Insurance program Credit management Cash Flow at Risk modeling Compliance program Manage Portfolio for Returns and Value Divestments

 

5 Financial Position - 3Q 2011 Moving forward from a position of strength $1.3 B Cash on Hand $3.0 B Liquidity Strong Ratios Debt-to-book capital 34% Net debt-to-book capital 26% Investment Grade Rating Moodys: Baa2 / stable outlook S&P: BBB / stable outlook Favorable Leverage to Peers Notes: Total debt and debt related metrics includes the Aseng FPSO lease and JV Installment Payments Maturity profile does not include $351 MM FPSO lease liability amortized over 15 years Debt-to-cap Ratio Debt-to-Cap Ratio NBL Peers NBL 0.29 0.36 Debt-to-Cap Ratio NBL Peers NBL 0.17 0.31 Net Debt-to-cap Ratio Peers listed in Appendix 36% 34% 31% 26% NBL NBL Peers Peers Well Managed Maturity Profile 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021+ JV Installment Payments 328 328 Bonds 200 1000 1284 Revolver 400 $MM 2012 2013 2014 2016 2019 2021+

 

6 Liquidity Maintaining strong liquidity Note: Methodology per S&P liquidity descriptors document dated July 2, 2010 Note: Data as of 2Q 2011 NBL A B C D E F Cash as % of Total Assets 0.1065 0.1826 0.04 0.072 0.086 0.07 0.028 Unused Credit Facility as % of Total Assets 0.1465 0.0701 0.18 0.11 0.096 0.083 0.059 $3.6 B Liquidity as a % of Total Assets Investment Grade Peers NBL D C A E B F Liquidity Sources / Uses 2.09 1.7 1.59 1.39 1.24 1.14 0.83 S&P Liquidity Metric "Strong" to "Exceptional Liquidity" 1.5X to >2.0X Investment Grade Peers

 

7 Credit Facility Renewal Scaled up to meet growth funding needs New Facility Closed During October 2011 $3.0 B facility $1.0 B accordion feature 5-year term International funding capability Attractive, flexible funding source Facility Size to Company Size Correlation 2100000000 3000000000 4000000000 3300000000 5000000000 4300000000 900000000 2650000000 2000000000 1810000000 2335000000 1250000000 1250000000 1400000000 1500000000 1500000000 4000000000 13282000000 13967000000 14339000000 43425000000 51800000000 32378000000 4005031000 32927000000 21624233000 3785388000 14233243000 7494000000 9679102000 8894937000 5498586000 6017463000 24193000000 NBL APA APC CHK COG DVN EOG FST MUR NFX PXD PXP RRC SWN TLM Investment Grade Peers Non-investment Grade Peers NBL New Facility NBL Old Facility Total Assets ($B) NBL with $1 B Accordion Feature Data as of Q2 2011 Facility Size ($B)

 

8 2012 Outlook Maintaining strong position moving forward 3Q 2011 2012 Projected Liqudity = Cash + Unused Credit Facility Capacity 2952 3396 Q3 2011 2012 Projected Debt-to-cap 0.34 0.32 Net Debt-to-cap 0.26 0.29 FFO-to-debt 0.61 0.68 $B Liquidity* Debt-to-cap and FFO*-to-debt * Terms defined in appendix

 

9 Enterprise Risk Management Integrated program across entire company Proactive Program in Place... Identify, Quantify, Prioritize, Manage and Mitigate Key Risks Linked to Key Business Processes Portfolio risks Annual budget / long range plan Exploration / New Ventures Major projects Global drilling Commodity hedging Assigned Risk Owners, Risk Matrices and Periodic Risk Workshops Deployed Through Business Regular Board Oversight and Review Integrated 10K / 10Q Risk Reporting and Disclosures Best-in-class Review Completed... Further Enhancements Planned for 2012

 

10 NBL Peers NBL Peers NBL Peers % Hedged 0.5 0.37 0.49 0.3 0.35 0.06 Commodity Hedging Proactively hedged through 2013 4Q11 2012 2013 Global Oil NBL Peers NBL Peers NBL Peers % Hedged 0.6000232827 0.44 0.37 0.38 0.25 0.15 4Q11 2012 2013 U.S. Gas Year Downside Protection Ceiling 2011 $80.32 $95.55 2012 $86.39 $98.07 2013 $97.62 $122.50 Year Downside Protection Ceiling 2011 $5.78 $6.74 2012 $5.22 $6.33 2013 $4.87 $5.54 Note: See appendix for a list of peers.

 

11 Cash Flow at Risk Modeling Robust across a wide range of business scenarios Monte Carlo Simulation 5,000 scenarios Commodity Price Range Oil: $52 - $195 / Bbl Gas: $2.92 - $8.31 / MMBtu Implied Commodity Price Volatilities Business Scenarios Production uncertainty CAPEX overruns Project delays Interest, Principal, Dividends Other CAPEX Strategic CAPEX Cumulative Operating Cash Flow 2011 - 2016, $B Operating Cash Flow Distribution 95% Confidence of Executing Strategic Projects Total Cash Needs Available Liquidity Prior Cash Flow Distribution Total Cash Needs Revised Cash Flow Distribution with Recent 30-year Financing Available Liquidity

 

12 Financial Projections Targeting strong liquidity as company scale grows 2009 2010 2011 2012 2013 2014 2015 2016 Liquidity* 2732 2830 3532 3396 3000 3000 3500 4471 NBL Liquidity Target 1500 1500 2000 2500 3000 3000 3500 4000 $B * Term defined in appendix

 

13 Financial Projections Maintaining metrics well within investment grade range 2009 2010 2011 2012 2013 2014 2015 2016 Net Debt-to-cap 0.14 0.15 0.28 0.29 0.34 0.37 0.38 0.31 Debt-to-cap 0.11 0.1 0.06 0.03 0.02 0.01 0.01 0.02 Incremental Debt-to-cap Due to Liquidity Targets 0.02 0.02 0.03 2009 2010 2011 2012 2013 2014 2015 2016 Funds From Operations / Total Debt 0.81 0.79 0.59 0.68 0.55 0.53 0.52 0.89 Debt-to-capital Ratios FFO* / Total Debt* BBB Rating A Rating * Terms defined in appendix

 

14 Financial Summary Continued Strong Financial Discipline Deploying growth capital at attractive returns Proactively Managing Capital Structure and Business Risks Maintaining Ample Liquidity and Conservative Balance Sheet for Financial Flexibility Well-positioned to Fund Growth and Exploration Program

 

Denver-Julesberg Basin Ted Brown SVP U.S. - Northern Region

 

2 DJ Basin Dramatic growth underway Leader in Innovation and Technology Application Significant Resource Potential Now Being Exploited Operational Performance Continues to Improve Defined Development Plan to Accelerate Activity Expanding Niobrara Play into Northern Acreage

 

3 NBL's Top Ten Niobrara Breakthroughs A leader in the horizontal play Best Producing Well in Wattenberg Proved Horizontal Viability in Vertically Developed Areas Longest Extended Reach Lateral Record Drill Time Partnered with Industry to Establish New Field Rules Testing 80-acre Density First EcoNode Multi-well Facility Expanded Wattenberg Field Limits into Low GOR Areas Initiated Simultaneous Stimulation Operations Integrated Niobrara Reservoir Characterization

 

4 DJ Basin Position Double-digit production growth over next five years Provides Huge Potential Over 840,000 net acres Net risked resources of 1.3 BBoe Significant Future Growth Strong production base of 67 MBoe/d, net with 54% liquids Active vertical and horizontal development programs Expect 15% 5-year CAGR Extensive technical and operational knowledge of the basin Leader in Innovation and Execution #1 oil producer in Colorado 2010 COGCC outstanding operator award in environmental protection Denver Cheyenne Greeley Fort Collins S.E. Wyoming N. Colorado Wattenberg

 

5 1st Qtr 2nd Qtr 3rd Qtr East 573 964 203 DJ Basin Resource Opportunity Net risked resources increased over 60% to 1.3 BBoe Horizontal Niobrara Driving Growth Further exploitation in vertically developed areas of Wattenberg field Multi-well pads lower cost Extended reach laterals improve F&D Potential upside with increased density Integrate Exploration Efforts Extensive 3D seismic database Driving expansion of Wattenberg field Key to unlocking the northern Niobrara play Pursuing multiple play types across the basin Stacked pay provides multiple targets Wattenberg Horizontal Non-Wattenberg Horizontal Wattenberg Vertical 2011 Net Risked Resources (BBoe) 6/1/2010 11/1/2011 Proved 310 319 Discovered Unbooked 125 812 Exploration 360 203 0.8 1.3

 

6 Wattenberg Horizontal Niobrara Entire area de-risked for development Superior Acreage Position Over 400,000 net acres 58 Producing Wells To-date 18 MBoe/d gross, 14 MBoe/d net All Areas Delivering Positive, Repeatable Results Average EUR of 310+ MBoe Extended Economic Area by 67% Full-scale Development Underway 5 - 6 rigs in 2012 8 - 10 wells completed per month 600+ MMBoe Net Risked Resources Extension Area 25 Wells Completed 480 Boe/d Avg. 30-day IP 70 - 90% liquids Greeley Core Area 22 Wells Completed 550 Boe/d Avg. 30-day IP 50 - 70% liquids High GOR Area 11 Wells Completed 750 Boe/d Avg. 30-day IP 40 - 50% liquids Core Area High GOR Area Extension Area NBL Horizontal Wells

 

7 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 71 72 73 74 75 76 77 78 79 80 81 82 83 84 85 86 87 88 89 90 Early Results 284.3478261 393.3884058 451.5434783 403.257971 438.5434783 513.2753623 532.8304348 533.057971 537.0434783 501.7681159 563.3623188 522.0144928 581.6884058 596.2971014 595.7028986 500.1855072 505.7289855 493.2 472.4695652 449.6101449 443.4072464 432.8086957 429.4028986 426.7652174 390.3855072 417.7623188 392.2043478 411.9434783 412.4663043 391.5068841 376.0068841 392.3068841 394.2391304 404.9782609 399.257971 372.8188406 356.2942029 356.3550725 355.7898551 343.2869565 352.8550725 331.9434783 370.8405797 349.673913 356.9347826 335.8550725 343.2971014 338.7753623 346.642029 333.0043478 331.2724638 333.7942029 301.1753623 321.3449275 314.1608696 301.2362319 317.026087 326.7144928 295.7043478 296.5884058 287.9173913 287.2086957 306.226087 299.6434783 293.3927536 290.084058 270.9202899 271.026087 285.2130435 268.7550725 251.073913 267.8811594 264.2942029 265.4681159 256.0869565 264.1231884 285.2318841 289.3913043 284.3188406 271.4971014 264.3666667 279.1956522 259.4710145 257.2869565 251.0942029 246.0623188 260.9565217 249.9347826 262.6927536 231.142029 Recent Results 235.3148148 411.4814815 481.7296296 456.0133253 441.0930556 477.008303 570.6444284 520.9210819 549.9328596 553.1587477 515.8373148 544.9000935 560.9458333 560.1551821 581.3497165 573.2868399 559.3118514 557.7348793 538.0400298 542.5232494 527.3351299 539.6016079 572.4792237 577.1411678 560.2210265 563.5508577 522.8296936 532.9100953 549.0714702 521.6091877 535.2845925 539.9289396 554.9369997 567.6790191 565.7938121 562.6806341 523.2477304 530.9245915 556.9521414 527.2145936 498.4648308 489.5923812 510.5837087 474.3441355 521.182275 497.0878571 485.403082 474.5591714 478.1807072 479.2615812 445.3210271 441.1727615 437.7226546 435.8257237 440.4059415 426.5391328 451.6376344 465.6834642 437.395205 449.3700694 452.6855412 434.6485808 419.7240482 434.7744085 425.6415278 432.9190234 421.7561626 411.8509365 409.7535778 416.1559829 408.2696867 408.9178006 435.7139632 415.463721 415.0559935 413.4384091 420.7093174 410.4907207 398.696036 397.195663 404.7319164 403.5080783 401.638149 393.8922822 360.0506559 410.8599527 411.2786259 409.7439689 387.286813 382.6498149 Early Results 30 Day Avg 467.265628 467.265628 467.265628 467.265628 467.265628 467.265628 467.265628 467.265628 467.265628 467.265628 467.265628 467.265628 467.265628 467.265628 467.265628 467.265628 467.265628 467.265628 467.265628 467.265628 467.265628 467.265628 467.265628 467.265628 467.265628 467.265628 467.265628 467.265628 467.265628 467.265628 Recent Results 30 Day Avg 523.2710726 523.2710726 523.2710726 523.2710726 523.2710726 523.2710726 523.2710726 523.2710726 523.2710726 523.2710726 523.2710726 523.2710726 523.2710726 523.2710726 523.2710726 523.2710726 523.2710726 523.2710726 523.2710726 523.2710726 523.2710726 523.2710726 523.2710726 523.2710726 523.2710726 523.2710726 523.2710726 523.2710726 523.2710726 523.2710726 Early Results 60-day Avg. 406.14 406.14 406.14 406.14 406.14 406.14 406.14 406.14 406.14 406.14 406.14 406.14 406.14 406.14 406.14 406.14 406.14 406.14 406.14 406.14 406.14 406.14 406.14 406.14 406.14 406.14 406.14 406.14 406.14 406.14 406.14 406.14 406.14 406.14 406.14 406.14 406.14 406.14 406.14 406.14 406.14 406.14 406.14 406.14 406.14 406.14 406.14 406.14 406.14 406.14 406.14 406.14 406.14 406.14 406.14 406.14 406.14 406.14 406.14 406.14 Recent Results 60-day Avg. 508.38 508.38 508.38 508.38 508.38 508.38 508.38 508.38 508.38 508.38 508.38 508.38 508.38 508.38 508.38 508.38 508.38 508.38 508.38 508.38 508.38 508.38 508.38 508.38 508.38 508.38 508.38 508.38 508.38 508.38 508.38 508.38 508.38 508.38 508.38 508.38 508.38 508.38 508.38 508.38 508.38 508.38 508.38 508.38 508.38 508.38 508.38 508.38 508.38 508.38 508.38 508.38 508.38 508.38 508.38 508.38 508.38 508.38 508.38 508.38 Wattenberg Horizontal Niobrara Production Curves Operational learnings generating better performance 23 Wells Avg. EUR 290 MBoe 18 Wells Avg. EUR 355 MBoe Gross Production Boe/d Days 25%

 

8 1/1/2010 1/2/2010 1/3/2010 1/4/2010 1/5/2010 1/6/2010 1/7/2010 1/8/2010 1/9/2010 1/10/2010 1/11/2010 1/12/2010 1/13/2010 1/14/2010 1/15/2010 1/16/2010 1/17/2010 1/18/2010 1/19/2010 1/20/2010 1/21/2010 1/22/2010 1/23/2010 1/24/2010 1/25/2010 1/26/2010 1/27/2010 1/28/2010 1/29/2010 1/30/2010 1/31/2010 2/1/2010 2/2/2010 2/3/2010 2/4/2010 2/5/2010 2/6/2010 2/7/2010 2/8/2010 2/9/2010 2/10/2010 2/11/2010 2/12/2010 2/13/2010 2/14/2010 2/15/2010 2/16/2010 2/17/2010 2/18/2010 2/19/2010 2/20/2010 2/21/2010 2/22/2010 2/23/2010 2/24/2010 2/25/2010 2/26/2010 2/27/2010 2/28/2010 3/1/2010 3/2/2010 3/3/2010 3/4/2010 3/5/2010 3/6/2010 3/7/2010 3/8/2010 3/9/2010 3/10/2010 3/11/2010 3/12/2010 3/13/2010 3/14/2010 3/15/2010 3/16/2010 3/17/2010 3/18/2010 3/19/2010 3/20/2010 3/21/2010 3/22/2010 3/23/2010 3/24/2010 3/25/2010 3/26/2010 3/27/2010 3/28/2010 3/29/2010 3/30/2010 3/31/2010 4/1/2010 4/2/2010 4/3/2010 4/4/2010 4/5/2010 4/6/2010 4/7/2010 4/8/2010 4/9/2010 HZ Well Count 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 HZ Production 0.22088 0.391546667 0.357013333 0.367973333 0.3692 0.4212 0.352666667 0.3004 0.631466667 0.594266667 0.524933333 0.5644 0.580666667 0.609066667 0.583066667 0.531653333 0.567117333 0.537650667 0.566717333 0.569386667 0.509917333 0.505384 0.491850667 0.467717333 0.448533333 0.474106667 0.493474667 0.445501333 0.439136 0.429926667 0.407793333 0.423522667 0.394309333 0.398058667 0.390330667 0.359381333 0.387514667 0.480056 0.508178667 0.455250667 0.381778667 0.476864 0.518354667 0.504705778 0.592972444 0.604705778 0.636026667 0.598722667 0.565645333 0.602458667 0.553874667 0.585706667 0.591117333 0.592045333 0.601133333 0.55856 0.51272 0.588184 0.566317333 0.562584 0.571506667 0.568722667 0.557504 0.557778667 0.568581333 0.860181333 1.094866667 1.056272 1.356986667 1.386181333 1.383258 1.336858 1.280152 1.288842667 1.336429333 1.422034667 1.258589333 1.097912 1.148797333 1.454093333 1.488845333 1.494690667 1.413250667 1.348445333 1.283872889 1.298126222 1.190659556 1.393912 1.354170667 1.438042667 1.363376 1.368122222 1.385322222 1.362398222 1.36964 1.267624 1.283205333 1.25416 1.217090667 Wattenberg Horizontal Niobrara Production More than tripled in last six months Controlled Flowbacks Laterals Lengthened to Avg. 4,500 ft. Stimulation Increased to 19 Avg. Stages * Excludes three early wells with inefficient frac design MBoe/d Net Horizontal Production First Well First 8 Wells Avg. 30 Wells* Last 18 Wells Liquids 120 270 315 355 EUR (MBoe) 120 270 315 355

 

9 Note: Wells costs $4.7MM, and reference price case. See appendix. Recent Results Exceeding Previous Type Curves Technical and Operational Learnings Enhancing Economics High Liquid Content Benefits Each Area Liquid Content by Area High GOR Area Core Area Extension Area Crude Oil 0.198 0.432 0.659 NGL 0.224 0.16 0.097 Natural Gas 0.578 0.408 0.244 Wattenberg Horizontal Niobrara Well Economics Strong returns continuing to improve 236 236 290 290 305 305 342 342 427 427 High GOR Area 0.467 0.3982 Core Area 0.345 0.2387 0.441 0.3729 Extension Area 0.246 0.1963 0.489 0.3915 Extension Area Type Curve Extension Area Recent Results Core Area Recent Results Core Area Type Curve High GOR Area After Tax ROR EUR (MBoe)

 

10 Wattenberg Horizontal Niobrara Drilling Continuous improvement Fit-for-purpose Rigs Spud to Rig Release Down Over 30% Pad Drilling Improving Efficiencies 1Q09 4Q09 1Q10 2Q10 3Q10 4Q10 1Q11 2Q11 3Q11 Spud to RREL 18.44 20.34 17.08 18.6 16.74 15.74 14.87 14.26 12.21 Days Spud to Rig Release Date 1Q09 4Q09 1Q10 2Q10 3Q10 4Q10 1Q11 2Q11 3Q11 Spud to RREL 1 1 2 4 6 7 4 11 25 Horizontal Completions Water Resources, Sand and Dedicated Frac Crews in Place Stimulation Frequency at Pace to Deliver the 2012 Plan

 

11 Wattenberg Horizontal Niobrara Field Tests Proof of concepts yield confidence and ability to deliver High Density Areas - No Interference Extended Reach Lateral - Better Capital Efficiency More Frac Stages - Improving Recovery Low GOR Extension Areas - Strong Returns 3D Seismic Data - Understanding of Subsurface Wellbore Orientation - Placement Makes a Difference

 

12 Horizontal Drilling in High Density Areas Lack of interference proves it is working Greeley

 

13 Repeatable "Gemini" Type Well Substantial potential within vertically developed areas Tanner K33-65HN NBL 100% WI 5,300 ft. lateral with 21-stage completion Drilled between 10 existing vertical wells Encountered original reservoir pressure Heitman 5 UPRC 8F UPRC 7F UPRC 6F UPRC 5F Sandau 12F Weber K10 Weber K33-09 Tanner K11 466 ft. 690 ft. 956 ft. 733 ft. 478 ft. 366 ft. 640 ft. 863 ft. 820 ft. 515 ft. Tanner K12 Tanner K33-65HN 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 71 72 73 74 75 76 77 78 79 80 81 82 83 84 85 86 87 88 89 90 Tanner K33-65N 0.1 164.1666667 333.8333333 434.3333333 663.3333333 543.8333333 700.5 758.8333333 830.3333333 873.3333333 840 897.1666667 1025.166667 1030.333333 1133.666667 1021.166667 942.6666667 1055.333333 1209.333333 1281.666667 1251.166667 1078.833333 1115.5 1106 1079.130545 1059.997486 1047.763049 1072.191096 1035.188128 1009.967548 1020.690833 996.7616667 1016.108333 960.1458333 883.3840665 1034.940847 951.1425 954.5566667 932.22 900.6041667 Average Vertical Well 0 71.52944444 68.35644444 68.35644444 68.35644444 66.68644444 66.68644444 56.68583333 60.35583333 59.19383333 58.52716667 58.19383333 56.27716667 57.56883333 57.12611111 57.12611111 57.12611111 49.45770833 48.344375 48.344375 48.344375 52.36027778 52.36027778 52.36027778 61.643125 61.851875 45.778125 48.491875 46.81222222 46.81222222 46.81222222 45.54125 45.54125 45.54125 45.54125 42.04666667 42.04666667 42.04666667 43.24895833 43.24895833 43.24895833 43.24895833 43.11777778 43.11777778 43.11777778 39.76729167 39.76729167 39.76729167 39.76729167 41.06083333 41.06083333 41.06083333 38.79216667 38.79216667 38.79216667 38.79216667 38.79216667 39.26666667 39.26666667 38.99645833 38.99645833 38.99645833 38.99645833 37.87805556 37.87805556 37.87805556 36.80791667 36.80791667 36.80791667 36.80791667 35.66861111 35.66861111 35.66861111 35.89020833 35.89020833 35.89020833 35.89020833 32.90388889 32.90388889 32.90388889 32.95703125 32.95703125 32.95703125 32.95703125 33.83444444 33.83444444 33.83444444 31.72270833 31.72270833 31.72270833 31.72270833 Gemini K01-99HZ 0.1 352.6666667 667.6666667 675.1666667 1013.333333 1059.833333 1033.333333 1006.5 959.5 996.3333333 1020 1132.5 1123.333333 1057.833333 1057.333333 1086.333333 1043.333333 1005.833333 913.8333333 976.6666667 938.5 934.1666667 733.6666667 1003.333333 974.5 1094.166667 1013.166667 1033.666667 1116.666667 1047.333333 1080.5 1011.333333 1022.166667 1036.333333 1098.5 1102.666667 1088.833333 1003.166667 1081.666667 1031.5 1007.666667 1029.333333 963 1057.333333 953.8333333 904.8333333 858.6666667 965.1666667 958.1666667 977.8333333 925 909.3333333 855.5 920.3333333 979.5 969.6666667 945.3333333 945.5 960.3333333 930.8333333 929.6666667 910.8333333 983 996.6666667 934.8333333 938 930.5 871.3333333 894 897.5 903.8333333 884.6666667 869.3333333 867.8333333 845.8333333 856.3333333 831.6666667 854.6666667 804.1666667 850 826.1666667 843.8333333 816.1666667 766 793.6666667 778 801.8333333 795.6666667 800.5 809.1666667 768.6666667 Avg. Vertical Well EUR 41 MBoe Gemini EUR 765 MBoe Gross Well Production Tanner

 

14 Extended Reach Lateral Results Encouraging 20% improvement in F&D costs Wells Ranch AE29 - 68HN NBL Operated with 100% WI Spud to rig release in 17 days 9,120 ft. lateral with 39-stage completion Early Results Suggest 20% Improvement in F&D Cost D&C $7.5 MM EUR indications of 600+ MBoe 10% of Horizontal Wells to Test Extended Reach Laterals in 2012 } Upper Niobrara Chalk 3D Base B Chalk 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 71 72 73 74 75 76 77 78 79 80 81 82 83 84 85 86 87 88 89 90 Wells Ranch AE29-68HN 0.1 48.66666667 78.66666667 256.6333333 152.7098552 283.86 201 340.3333333 32.93940437 531.3333333 586.1666667 526.8333333 615.1666667 650.5 660.9507785 698.9587685 755.745691 754.5229956 869.9068486 774.8473899 732.0610195 700 750 825.8177343 827.9101089 865.7467429 843 869.5 871.1666667 919.6666667 891.3124479 763.5 719.1666667 862.3333333 903 884.1666667 908.1666667 900.6666667 911.1666667 918.5 908 907.8333333 906.1666667 891.3333333 896.1666667 865.8333333 901.6666667 883.5 865.8333333 890.5 885.5 864.6666667 893.1666667 840.8333333 835.5 846.3333333 825.3333333 864.1666667 818 850 835 832.5 842.3333333 831.3333333 816.5 798.5 811.3333333 784.5 791.5 778.3333333 782.1011763 792.8333333 780 777.5 775.1666667 778 777.1666667 781.6666667 772.5 758.9 781.1666667 789.8595243 731.6666667 783.0333333 763.8666667 757.7336909 755.4 796.925415 795.0666667 698.6257847 759.435058 310 MBoeDecline 515.1067623 510.9418768 506.7769913 502.6121059 498.4472204 494.2823349 490.1174494 485.9525639 481.7876784 477.6227929 473.4579074 469.2930219 465.1281364 460.963251 456.7983655 452.63348 448.4685945 444.303709 440.1388235 435.973938 431.8090525 427.644167 423.4792815 419.314396 415.1495106 410.9846251 406.8197396 402.6548541 398.4899686 394.3250831 390.1601976 387.7431769 385.3261561 382.9091353 380.4921146 378.0750938 375.658073 373.2410523 370.8240315 368.4070108 365.98999 363.5729692 361.1559485 358.7389277 356.3219069 353.9048862 351.4878654 349.0708447 346.6538239 344.2368031 341.8197824 339.4027616 336.9857408 334.5687201 332.1516993 329.7346785 327.3176578 324.900637 322.4836163 320.0665955 317.6495747 316.0549308 314.4602868 312.8656429 311.270999 309.676355 308.0817111 306.4870671 304.8924232 303.2977792 301.7031353 300.1084913 298.5138474 296.9192034 295.3245595 293.7299155 292.1352716 290.5406276 288.9459837 287.3513398 285.7566958 284.1620519 282.5674079 280.972764 279.37812 277.7834761 276.1888321 274.5941882 272.9995442 271.4049003 Boe/d

 

15 Target Multiple Stacked Pay Zones Niobrara B and C chalks Codell sandstone Possibly Greenhorn chalks Detailed Subsurface Understanding Identify faults to optimize lateral length and placement Drives a fully integrated development plan Multiple zones, multiple wells per section Capture 3D Over Entire Lease Position in Next Three Years Own or have access to over 1,800 sq. mi. Complex Areas of Niobrara Unlocked 3D seismic improves technical capabilities

 

16 DJ Basin Niobrara Comparison Niobrara contains significant amounts oil and gas Property Niobrara Eagleford Bakken Depth 5,500 - 8,200 ft. 6,000 - 8,000 ft. 7,000 - 11,000 ft. Thickness 250 - 350 ft. 200 - 300 ft. 75 - 150 ft. Porosity 7 - 12% 4 - 15% 8 - 12% TOC 1.5 - 10% 5% 9% Ro 0.7 - 1.4% 0.5 - 1.3% 0.6 - 1.0% GOR (CF/BO) 500 - 30,000 500 - 2,000 500 - 1,000 Sw 10 - 60% 15 - 45% 15 - 25% OOIP (MMBoe/sec) 25 - 40 30 - 50 10 - 15 Dakota Sand Pierre Shale Sussex (Terry) SS Pierre Shale Shannon (Hygene) SS Pierre Shale Niobrara "A" Chalk Niobrara "B" Chalk Niobrara "C" Chalk Ft Hays Limestone Codell SS Carlile Shale Greenhorn LS Graneros Shale D Sand J Sand J3 Sand Skull Creek Shale Sharon Springs DJ Basin Stratigraphy Niobrara Horizontal Targets Source: Internal, Tudor Pickering

 

17 Historical Wattenberg Development Plan Increased vertical density yielded a low recovery factor Conventional Plan of Development - Increase Vertical Well Density Early Approach 32-acre Well Spacing (20 Wells per Section) 2006 COGCC Rule Change Allowed 20-acre Well Spacing (32 Wells per Section) EUR from Vertical Drilling Only 1.5% OOIP from Niobrara Pierre Shale Niobrara Greehorn LS J Sand Dakota Sand 100% 1% 5% 10% 60% 40% 20% 80% OOIP Recovery

 

18 Wattenberg Current State Adding horizontal wells with 160-acre spacing X BHL SHL G E M I N I 1% 5% 10% 60% 40% 20% 100% 80% OOIP Recovery Early Success with Gemini in Heavily Drilled Section (18 wells) Demonstrated Repeatability with Over 50 Wells Completed Average EUR 310+ MBoe 2,000+ Locations and 600 MBoe of Net Unrisked Resources Increasing EUR from 1.5% to 6% OOIP

 

19 1% 5% 10% 60% 40% 20% 100% 80% OOIP Recovery Niobrara Wattenberg Future State Pad drilling, 80-acre spacing and EcoNodes Currently Evaluating Viability of 80-acre Horizontal Well Spacing Piloting 9 horizontal wells in 1 section, 2 pads Testing 300 and 600 ft. lateral spacing Utilizing Multi-well Pads and Central Production Facilities Minimize surface footprint More efficient execution and operations Successful 80-acre Results Yields Incremental Unrisked Resources EUR Increases to Over 10% of OOIP

 

20 Drilling Pads with EcoNode Centralized Facilities Providing operational efficiency Efficient Pad Concept with Facilities on Central Site Water Pumped to Well Pads for Drilling and Hydraulic Fracturing Produced Fluids Delivered to EcoNode Facility by Pipeline 8-well pad with EcoNode in background EcoNode with temporary frac water tanks

 

21 Wattenberg Horizontal Niobrara Development Plan Addressing the supply chain increases the certainty of execution Approximately 3,900 Potential Locations Rig Count and Completions to Double within Two Years Contracts awarded for new build rigs Dedicated crews and equipment Sand procured Aligned with service providers Water management system in place Procurement, transportation, storage, disposal and recycle Organizational Capacity Increasing 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 Base 92 135 208 246 246 246 246 246 246 246 Accelerated - - 17 54 154 154 154 154 154 154 Cum Base 127 262 470 716 962 1208 1454 1700 1946 2192 Accelerated Cum 127 262 487 787 1187 1587 1987 2387 2787 3187 Horizontal Niobrara Wells

 

22 DJ Basin Takeaway Capacity Third parties expanding to meet producer's needs Natural Gas Processing Expansions DCP completed Mewbourn II expansion, next is LaSalle for 100 MMcf/d by mid 2013 Others expected to add 500 MMcf/d of capacity by mid 2014 Incremental NGL transport being developed in conjunction with new processing Additional Oil Capacity Through Pipeline Expansions and Rail NBL increased flexibility from one to 5 outlets White Cliffs expanding to 50,000 Bbl/d, further increase of 30,000 Bbl/d planned for 2012 Evaluating in-field oil gathering system to reduce trucking traffic 10/31/2011 11/30/2011 12/31/2011 1/31/2012 2/29/2012 3/31/2012 4/30/2012 5/31/2012 6/30/2012 7/31/2012 8/31/2012 9/30/2012 10/31/2012 11/30/2012 12/31/2012 1/31/2013 2/28/2013 3/31/2013 4/30/2013 5/31/2013 6/30/2013 7/31/2013 8/31/2013 9/30/2013 10/31/2013 11/30/2013 12/31/2013 1/31/2014 2/28/2014 3/31/2014 4/30/2014 5/31/2014 6/30/2014 7/31/2014 8/31/2014 9/30/2014 10/31/2014 11/30/2014 12/31/2014 1/31/2015 2/28/2015 3/31/2015 4/30/2015 5/31/2015 6/30/2015 7/31/2015 8/31/2015 9/30/2015 10/31/2015 11/30/2015 12/31/2015 1/31/2016 2/29/2016 3/31/2016 4/30/2016 5/31/2016 6/30/2016 7/31/2016 8/31/2016 9/30/2016 10/31/2016 11/30/2016 12/31/2016 Current Capacity 840000 840000 840000 840000 840000 840000 840000 840000 840000 840000 840000 840000 840000 840000 840000 840000 840000 840000 840000 840000 840000 940000 940000 940000 940000 940000 940000 940000 940000 940000 940000 940000 940000 940000 940000 940000 940000 940000 940000 940000 940000 940000 940000 940000 940000 940000 940000 940000 940000 940000 940000 940000 940000 940000 940000 940000 940000 940000 940000 940000 940000 940000 940000 NBL Portion of Expansion - - - - - - - - - - - - - - - - - - - - - 120000 120000 120000 120000 120000 120000 120000 120000 120000 195000 195000 195000 195000 195000 195000 195000 195000 195000 195000 195000 195000 195000 195000 195000 195000 195000 195000 195000 195000 195000 195000 195000 195000 195000 195000 195000 195000 195000 195000 195000 195000 195000 Developing Expansions - - - - - - - - - - - - - - - - - - - - - 230000 230000 230000 230000 230000 230000 230000 230000 230000 305000 305000 305000 305000 305000 305000 305000 305000 305000 305000 305000 305000 305000 305000 305000 305000 305000 305000 305000 305000 305000 305000 305000 305000 305000 305000 305000 305000 305000 305000 305000 305000 305000 NBL Gross Op Wellhead Gas 260907 260938 260968 260999 261029 261060 261090 261121 285501 285531 285562 285592 285623 285653 285684 285714 285744 285775 285805 285836 332309 332339 332370 332400 332431 332461 332492 332522 332552 332583 332613 332644 378728 378758 378789 378819 378850 378880 378911 378941 378971 379002 379032 379063 416654 416685 416715 416746 416776 416807 416837 416868 416898 416929 416959 416990 443340 443370 443400 443430 443460 443490 443520 7/31/2011 8/31/2011 10/31/2011 12/31/2011 7/31/2012 1/31/2013 7/31/2013 1/31/2014 7/31/2014 1/31/2015 7/31/2015 1/31/2016 7/31/2016 Current Capacity 71.5 93.5 100.5 118.5 125.5 135.5 145.5 150.5 155.5 155.5 155.5 155.5 155.5 NBL Portion of Expansion 0 0 0 0 0 2.475 4.125 5.775 5.775 22.275 22.275 38.775 38.775 Developing Expansions 0 0 0 0 0 5.025 8.375 11.725 11.725 45.225 45.225 78.725 78.725 NBL Gross Op Oil Production 27.38 30 31.201 32.805 35.085 37.7 43.582 51.816 60.05 65.7035 71.357 75.0475 78.738

 

23 Central DJ Basin - Niobrara Significant acreage position outside Wattenberg Approximately 440,000 Net Acres Low entry cost - $480 per acre Largely operated by NBL Capitalizing on Industry Knowledge to Expand Success Continue to Appraise N. Colorado and S. Wyoming Drill 2 wells in 4Q 2011 Plan for 1 rig program in 2012 Testing fractures, matrix, lateral geometry and completion designs Over 1,000 sq. mi. of 3D seismic planned for 2011 Evaluating Infrastructure Needs and Optimum Completion Techniques Seismic Outlines WY NE Fort Collins CO Cheyenne CO

 

24 DJ Basin Production Outlook Liquids content and horizontal activity drives growth Horizontal Production Increases Nine Times Liquid Production Doubles 2012 - 2016 Capital $8 B Horizontal Vertical Other East 5329 1888 840 Horizontal Other Vertical 2011 38% 16% 46% 2016 53% 13% 34% Product Mix Crude Oil NGLs Natural Gas MBoe/d Net Production 2011 2012 2013 2014 2015 2016 Vertical 53.81 53.18 51.9 51.83 51.97 53.05 Horizontal 8.025 18.76 33.49 50.8 63.66 72.27 Liquid Content 33.39 40.57 50.21 62.81 73.54 82.7

 

25 DJ Basin Positioned for dramatic growth 1.3 BBoe of Net Risked Resources Horizontal Resource Potential Could Increase Through Tighter Well-spacing Increase Niobrara recovery to 6 - 12% OOIP Production Doubles in Five Years Liquid Percentage Climbs to Over 65% Leader in Innovation and Technology Application

 

Marcellus John Lewis VP U.S. - Southern Region

 

2 Marcellus Great strategic fit for NBL High-quality, Well-positioned Asset Lowest cost U.S. gas play Innovative JV Structure and Aligned Partner Manageable Multi-year Development Plan Operating results already showing improvement Ready to initiate NBL operations and transfer multi-disciplinary expertise to the JV Fifth Core Area for NBL Low risk, predictable and sustainable growth Material cash flow and net income Significant resources Rebalances portfolio

 

3 Marcellus JV Position Significant scale and impact Large Acreage Position Within Marcellus Fairway 50% of 628,000 net acres Located in both wet and dry gas windows High NRI (~88%) 87% of Acreage Held by Production Allows flexibility in development and lowers cost Requires fewer permits and smaller environmental footprint Net Risked Resources Initially Estimated at 7.4 Tcfe to NBL Access to Established Infrastructure OH PA WV MD VA Wet Gas Dry Gas Dry Gas Wet Gas

 

4 Benefits of Partnering with CNX Built in efficiencies to jump-start operations Well-established Appalachian Operator Experienced Land and Permitting Staff Excellent Safety and Environmental Record Unique Synergies Coordinated Long-term Development in Coal Areas Access to existing water supply sources Share investments in water supply, roads and other infrastructure Use of surface on fee acreage and existing right-of-ways Similar Corporate Values

 

5 Marcellus Sweet Spot Initial activity concentrated in SW PA Industry Recognized Sweet Spot in SW PA Key Geologic Attributes Systematic Development and Expansion Adds Efficiency Continue to Test Other Acreage for Future Development SW PA Sweet Spot Dry Gas Wet Gas

 

6 Early Results Exceeding Expectations New pad adding significant production Hutchinson 10-well Pad Initial production rates 5 - 12 MMcf/d 5 wells 5 - 8 MMcf/d 5 wells 9 - 12 MMcf/d Potentially Extends Sweet Spot Further North Pad Location SW PA Sweet Spot Dry Gas Wet Gas

 

7 Marcellus Well Results Comparison CNX wells improving, now exceeding industry average CNX Wells in SW PA Yield 21% More Production Over 500 Days Mcf/d Gross Wellhead Gas Production CNX Avg. 2010-2011 (39 laterals ~2,859 ft.) Comp. Avg. 2009-2010 (103 laterals ~2,800 ft.) CNX Avg. 2008-2009 (13 laterals ~1,625 ft.) NBL Acq. Model (normalized to 2,860 lateral ft.)

 

8 Marcellus Individual Well Economics Innovative deal structure maintains returns at low gas price 2.5 3 3.5 4 5 6 7 7.5 SW PA Dry (6 Bcf) 10.2 15.8 21.8 SW PA Dry (7 Bcf) 14.9 21.9 29.3 SW PA Dry 6 Carry 12.4 21.1 31 41.9 SWPA Dry 7 Carry 17.4 28.5 41 56 No Carry Carry Note: Assumes $6 MM well cost, 7 Bcf EUR

 

9 Marcellus Drilling and Completion Cost Lateral lengths increasing while gaining efficiencies 2009 2010 2011 Lateral 2200 2400 3850 Drilling 200 190 166 Completion 300 235 220 Lateral Length Ft. 2009 2010 2011 Lateral 2200 2400 3850 Drilling 200 190 166 Completion 300 235 220 17% Improvement $/Ft. Drilling Cost 2009 2010 2011 Lateral 2200 2400 3850 Drilling 200 190 166 Completion 300 235 220 29% Improvement Completion Cost $M/Stage

 

10 Marcellus JV Work Process Utilize major project expertise Long-term, Systematic Approach Joint rolling 3-year plans Systematic development of wells and infrastructure Semi-annual Best Practices Workshops Defined joint technical committees Set targets for improvement Ongoing knowledge transfer to enhance and accelerate learnings Supply Chain Optimization

 

11 Marcellus JV Drilling Plan Controlled and steady ramp-up 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 CNX 103 148 198 221 236 236 236 236 236 236 NBL 37 79 120 133 141 141 141 141 141 141

 

12 NBL's Near-term Drilling Plan HBP and fee acreage enables efficient development Focused Infrastructure Development Pad Drilling Locations Identified Through 2015 2012 39 wells drilled with 1 rig ramping to 3 rigs 2013 81 wells drilled with 3 rigs ramping to 4 rigs Marshall County Washington County Well Legs Pipelines 2014 - 2015 131 wells drilled with 5 rigs ramping to 6 rigs

 

13 CNX's Near-term Drilling Plan Pad drilling for efficiency and cost control N Nineveh 2 N Nineveh 1 Morris Rutan CNX's 2012 and 2013 Drilling Program Focused on Greene and Washington Counties in PA Water and Gathering Lines Connect with NBL Operated Area OH PA WV MD VA Wet Gas Dry Gas

 

14 Water Sourcing Plan for SW PA Supply established and infrastructure build out underway Sufficient for 16 Frac Stages per Day Moving Water by Pipeline Reduces environmental and safety risk Smaller activity footprint Improves efficiency of completion operations Lowers overall costs External source to Majorsville 350 GPM optional - N. Nineveh Nineveh Greenhill Morris Leatherwood Alex Paris Rutan Majorsville Columbian Chemical Ohio River to Majorsville 800 GPM Ohio River via Shoemaker Mine 500 GPM N. WV R.O. Project 1000 GPM Alex Paris Booster Project 800 GPM

 

15 Gas Gathering System Plan for SW PA Systematic expansion to stay ahead of drilling activity Gas Gathering System Installed or Under Construction to Support 2012 Drilling Pad Drilling Allows for Lower Number of Permits, Efficiency and Reduced Costs Early Infrastructure Development Creates Backbone for Future Expansion Firm Transportation and Processing Contracts Cover Production Through mid 2014 Firm - 365 MMBtu, net Processing - 115 MMBtu, net OH PA WV MD VA Dry Gas Wet Gas

 

16 NBL's Impact on JV Applying our core competencies and transferring learnings Experience with Wattenberg Unconventional Reservoirs Integrated Subsurface Approach Project Management Skills Supply Chain Management Complementary EHS Culture

 

17 NBL Operational Readiness Prepared for operations January 1 Opened Office in Canonsburg, PA Core Operations Staff on the Ground Designed Organization and Processes Using Wattenberg Best Practices Service Contracts Established and Long-lead Material Ordered First Operated Rig Starts in January Leveraging CNX Expertise for Rapid Startup of Operations

 

18 2011 Marcellus JV Production Net NBL production has doubled since initial announcement MMcf/d Announcement Closing Today Year-end MMcf/d 35 50 69 82 Announcement 8/18/2011 Closing 9/30/2011 Today 11/15/2011 Projected 12/31/2011 Net Production 35 50 69 ~ 80

 

19 Marcellus JV Production Outlook Rapid growth with long plateau 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 CNX and NBL 39 103 241 420 610 763 898 903 891 921 942 NBL Net Production MMcfe/d 2012 - 2016 Capital $6 B Drilling Carry Facilities Other Capital 4061 1350 468 165 Facilities Drilling Carry Other

 

20 Marcellus Fifth impact area for NBL Unique Opportunity in Lowest Cost Gas Play Synergies and Alignment Between CNX and NBL Enhances Value Net Production Reaches 600 MMcfe/d in 2015 7.4 Tcfe of Net Risked Resources and Growing Operational Learnings will Improve Results Over Time

 

Gulf of Mexico John Lewis VP U.S. - Southern Region

 

2 Gulf of Mexico NBL committed to the deepwater Deepwater Returning to a "New" Normal NBL Led the Industry Back Progress Occurred on Numerous Fronts During the Moratorium Development Projects Will Soon Deliver Significant Value Exploration Portfolio is Robust and has Matured

 

3 Deepwater Gulf of Mexico A "New" normal A "New" normal A "New" normal

 

4 Deepwater Gulf of Mexico NBL led the industry back NBL Industry Firsts Post Macondo 1st blowout preventer certification 1st completion permit 1st drilling permit 1st new production from exploration (Santiago) Organized and Led the Development of Helix Subsea Containment System (HWCG) Solicited and coordinated the participation of 24 GOM operators Chaired HWCG Technical Committee Arranged and guided meetings with BOEM Recognized by BOEM as Best-in-class Operator

 

5 Galapagos Subsea Development Significant progress in the last year 132 MMBoe Gross Resources 36 MMBoe, net NBL 29% Average WI Operates Santa Cruz and Santiago Accomplishments Over the Last Year Drilled the Santiago discovery well Preformed completions at Isabela and Santa Cruz Advanced host facility and subsea construction work Estimated initial flow rate increased to 10 MBbl/d net Multiple Low-risk, Follow-on Opportunities NaKika Santiago 23.25% WI Santa Cruz 23.25% WI 562 563 606 519 Isabela 33.33% WI

 

6 NaKika Isabela Santiago Santa Cruz Galapagos Field Layout Subsea tieback development 6,500 ft. water depth Dual 8 in. pipe-in-pipe flowlines Initial 3-well development

 

7 Galapagos Production Outlook Sustained production plateau Net Production 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2010 Base 5.069 8.557 9.809 8.965 11.633 11.438 9.406 7.593 8.271 7.197 2.997 Base Case 0 9.244 8.136 11.024 9.41 12.798 10.558 8.604 7.086345426 8.96251791 5.149930641 2.442757016 2.02399635 1.677223363 0.359193703 1.408885238 Upside Recoveries 0 5.394 8.685 8.262 8.401 3.872 5.082 4.202 1.34372439 -3.373295916 -1.707800593 -0.284975587 -1.069976272 0.346159252 4.431235683 -0.515663701 MBoe/d Development well at Isabela Development well at Isabela / Sleeve Shift at Santa Cruz

 

8 Initially Three Well Subsea Tieback Base Case Economic Summary Net resources 36 MMBoe Net capital $462 MM F&D $12.70/Boe AT ROR 41% Life cycle AT NPV10 $0.8 B Point forward AT NPV10 $1.1 B Upside Recovery Adds 15 MMBoe net resources and $0.6 B AT NPV10 Galapagos Project Economics Strong cash flow and returns Cum $B $MM 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 Base AT Cash Flow 158.929 123.828 213.576 192.405 251.641 210.736 174.322 137.842 99.284 73.677 50.153 41.899 31.289 2.492 35.822 47.091 Base Cum AT Cash Flow -0.015435 -0.019206 -0.078543 -0.161961 -0.22162 -0.062691 0.061137 0.274713 0.467118 0.718759 0.929495 1.103817 1.241659 1.340943 1.41462 1.464773 1.506672 1.537961 1.540453 1.576275 1.623366 Upside Recoveries Cash Flow 92.728 137.927 159.196 125.533 84.674 117.871 95.331 40.973 20.01 0.15 -3.107 -29.465 -18.281 55.762 -24.767 -47.091 Upside Recoveries Cum AT CF -0.015435 -0.019206 -0.078543 -0.161961 -0.22162 0.030037 0.291792 0.664564 0.982502 1.318817 1.647424 1.917077 2.095892 2.215186 2.289013 2.336059 2.348493 2.361501 2.419755 2.43081 2.43081 Investments -22.533 -4.883 -80.052 -116.634 -84.685 -25.813 -55.259 -3.279 -50.034 0 0 0 -11.717 0 0 0 0 0 -9.203 0 0 * * Term defined in appendix Note: Utilizing reference price case. See appendix

 

9 Galapagos Additional Resource Potential Complementary follow-on upside Four Offsets Identified To-date Oil and gas potential 40 MMBoe gross mean resource potential Shallow Zone Upside Discovered in Santa Cruz Confirmed as oil in Santiago 25 MMBoe gross mean resource potential MC 562 MC 563 MC 519 Isabela Santiago Santa Cruz Discoveries Prospects Shallow Zones Well Locations

 

10 Gunflint Discovery NBL's largest GOM find to-date NBL Operated with 26% WI Complex Subsalt Miocene Structure Encountered Over 550 ft. of Net Pay High-quality Sands Porosity 20 - 26% Permeability 200 - 1,000 millidarcy Progress Made in the Last Year Signed unitization agreement Advanced appraisal permitting and drilling Performed development concept and front-end engineering studies 904 948 992 993 949 Devil's Tower Tubular Bells Kodiak Gunflint 26% WI

 

11 M-53 M-48 M-50 M-54 Gunflint Well Log Over 550 ft. of net pay

 

12 Gunflint Discovery Finalized equity determination Interest Holders in All Gunflint Area Blocks Agreed to Final Joint Equity NBL Designated as Operator with 26% WI Added Blocks 992 and 993 to the Project Area Advantages to Early Equity Agreement Saves 1 - 2 years of post appraisal negotiations prior to project sanction Increased capital efficiency - true appraisal wells vs. equity appraisal wells Establishes alignment of partnership on appraisal and development decisions

 

13 Gunflint Appraisal Program Determining the ultimate size Gross Resources of 70 - 500+ MMBoe Appraisal Activity First appraisal well to spud in December 1 - 2 additional wells to fully evaluate Scalable Development Plan Economically viable with existing discovered resources Front-end conceptual studies completed Salt Discovery Well 1st Appraisal Well Appraisal Areas

 

14 Gunflint Production Outlook Significant impact 2016 2017 2018 2019 2020 2021 250 MMBoe Case 34.6 29.2 23.3 17.8 12.8 8.3 520 MMBoe Case 0 5.7 11.7 17.2 22.4 26.7 MBoe/d Net Production Facility Limited

 

15 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 Base AT Cash Flow* 513 483.5 383.3 301.5 222.7 146.9 Base Cum AT Cash Flow -0.043 -0.043 -0.046 -0.077 -0.143 -0.285 -0.477 -0.699 -0.186 0.297 0.68 0.982 1.205 1.352 Upside Recoveries Cash Flow 0 0 0 0 0 0 -0.699 110 265.4 360.8 453.3 486.6 Upside Recoveries Cum AT CF -0.043 -0.043 -0.046 -0.077 -0.143 -0.285 -0.497 -0.719 -0.228 0.392 1.067 1.752 2.436 3.022 Investments -38 0 -3 -42 -90 -193 -260 -301 -62 0 Upside Investment -27 0 -124 -63 Stand Alone Facility with Nine Subsea Wells Base Case Economic Summary Gross resources 250 MMBoe Net resources 57 MMBoe Net capital $1.3 B F&D $22.95/Boe AT ROR 26% AT NPV10 $0.6 B Upside Potential Adds 61 MMBoe net resources and $1.1 B AT NPV10 Gunflint Mean Resource Economics Project payout in approximately two years * Term defined in appendix Note: Utilizing reference price case. See appendix Cum $B $MM

 

16 Deep Blue Prospect Sidetrack data being reviewed NBL Operated with 33.75% WI Original Well Encountered Hydrocarbons Multiple high-quality reservoirs Excellent hydrocarbon fluid properties Sidetrack has Reached Total Depth Found high-quality reservoirs Additional hydrocarbons encountered Louisiana Green Canyon

 

17 Deepwater GOM Prospect Inventory Focus on subsalt Miocene 0 - 100 101 - 200 201 - 530 0 - 100 101 - 200 201 - 530 Structure Amplitude Prospect Gross Size (MMBoe) 39 prospects 2 BBoe net unrisked mean resources 500+ MMBoe net risked mean resources

 

18 Development ScenarioPrimary Prospect Type Total Portfolio Subsea Tieback Amplitude Play Subsea TiebackSubsalt Miocene Stand AloneSubsalt Miocene Number in NBL's Portfolio 39 9 7 23 Total Gross Unrisked Mean Potential (BBoe) 6.0 0.5 0.6 4.8 Average Chance of Drilling 59% 37% 36% Prospect Class Totals Risked AT NPV10 ($MM) $4,000 $700 $400 $2,800 Success Case AT NPV10 ($MM) $18,000 $2,000 $2,000 $14,000 Deepwater GOM Exploration Value $4 billion risked present worth to NBL Note: Utilizing reference price case. See appendix.

 

19 Deepwater Exploration Prospects for 2012 and 2013 Multiple options for one-rig program Amplitude Subsalt Dirac Sailfish Troubadour Big Bend Floreana Silvergate Genovesa Talon Palladium Ness Deep Top Aleutian Madison Clingmans Dome Dantzler 6 amplitude with 32 MMBoe net risked resources 8 subsalt with 176 MMBoe net risked resources

 

20 Deepwater GOM Production Outlook Development and exploration growth contributors 2011 2012 2013 2014 2015 2016 Base 14173 8600 1615 1661 3875 1362 Development 536 2722 1864 1102 970 263 Galapagos 0 8295 7575 10350 16179 14783 Exploration tiebacks 0 0 1593 5860 7329 Gunflint 0 34638 Net Production MBoe/d 2012 - 2016 Capital $2.4 B Gunflint Galapagos Other Development Exploration Capital 925 110 17 1342 Exploration Other Gunflint Galapagos

 

21 Gulf of Mexico Converting resources to value NBL Excels as an Explorer in the Deepwater Deepwater Major Projects Build Off International Learnings and Processes to Deliver Execution Excellence Two Development Projects Online in 2012 Contributing 13 MMBoe/d, Net Nearly 500 MMBoe Net Risked Potential Resource Captured

 

West Africa Rodney Cook SVP International

 

2 West Africa Building long-term value Existing Core Assets Providing Strong Cash Flows Initial Major Projects Focused on Liquid Developments Demonstrating Best-in-class Project Management Capabilities Additional Upside in Douala Basin Progressing Regional Gas Monetization Plans

 

3 West Africa Key position of value for NBL West Africa Bioko Island Cameroon Block O 45% WI Block I 38% WI YoYo Mining License 50% WI Alba Field 34% WI Methanol Plant 45% WI LPG Plant 28% WI Equatorial Guinea Tilapia PSC 50% WI

 

4 Alba Field Base asset with strong cash flow Current Net Volumes 20 MBbl/d, 244 MMcf/d 2010 Net Reserves 59 MMBbl Liquids, 869 Bcf Natural Gas Natural Gas Commercialized with LPG Processing and Sales to Methanol and LNG Plants Low Unit Costs LOE: $3.55/Boe DDA: $2.10/Boe * Term defined in appendix Note: Utilizing reference price case. See appendix $MM Cum $B

 

5 West Africa Operated Discoveries Setting the stage for growth 305 MMBoe Net Discovered Resources 111 MMBbl liquids and 1.17 Tcf gas High deliverability reservoirs Project Lineup Aseng - first oil November 2011 Alen - sanctioned, first oil 4Q 2013 Diega - evaluating development options Carla - recent discovery Gas monetization - ongoing planning and evaluation Continuing Exploration Bioko Island Block O Block I YoYo Mining License

 

6 Aseng Field Breakthrough execution increases project value Development Cycle Times Discovery to production less than 5 years Sanction to production under 3 years First Oil Seven Months Ahead of Schedule Value enhancement of $80 MM net AT NPV10 First oil November 6, 2011 Capital Investment 13% under Approved Levels Driven by subsea cost effectiveness $70 MM net capital savings Resources 30% Above Initial Estimates Brent Oil Price 43% Higher than Sanction Economics Initial Rate of 50 MBbl/d, 17 MBbl/d, Net Best-in-class Safety Performance

 

7 3,000 ft. water depth Two, four-slot manifolds Four production risers Gas lift provided in umbilicals Aseng Field Layout Seven months ahead of schedule

 

8 Aseng Project Philosophy Achieving a breakthrough outcome Proven Project Management Team Cohesive and Fully Integrated Technical Organization Win-win Incentive Programs with Suppliers Extensive Pre-planning and Testing Proactive Safety Programs Rigorous Cost Control and Scheduling Extensive Peer Reviews and Third Party Assessments Transparent Communication with All Stakeholders

 

9 Over 10.5 MM man hours with no major accidents Total recordable incident rate (TRIR) of 0.21 Only 408 total man hours lost for all incidents Aseng FPSO Safety Award Ceremony Best-in-class safety record in all aspects of the project

 

10 Aseng Project Philosophy - Subsurface Disciplined front-end loading yields world-class execution Rigorous Appraisal Program Evaluate, test, core and sample appraisal wells early in program Appraisal and Development Programs Reduced Uncertainty and Optimized Well Placement for Ultimate Recovery 3 pre-sanction penetrations 20 penetrations in reservoir 10 final completed wells with 5 horizontal producers Production Basis of Design Focuses on Value Addition System accommodates wide range of GOR, water cut and injection parameters Redundancy to allow for maximum reliability Ability to connect other developments subsea

 

11 Aseng Subsurface Results Resource estimate growing with development 43 MMBbl Net Resource for Oil Recovery Phase 128 Bcf net gas resource Five Horizontal Producers, Three Water and Two Gas Injectors Pressure Maintenance System to Maximize Recovery High Deliverability Reservoir Requires Fewer Wells Avg. permeability 5 darcy Avg. porosity 26% Technology Used for Optimum Reservoir Enhancement Recoverable Resources 30% Above Initial Estimates

 

12 Aseng FPSO On location in Equatorial Guinea 1,089 ft. long and 184 ft. wide 80 MBbl/d oil treating capacity 120 MBbl/d total fluids production 150 MBbl/d water injection 160 MMcf/d gas injection 170 MMcf/d gas production 1.6 MMBbl storage

 

13 2012 2013 2014 2015 2016 17.096 17.03 15.241 14.09 12.06 MBbl/d Net Crude Oil Production Aseng Production Outlook Providing immediate value-added growth

 

14 Aseng Economics Strong cash flow generation Economics Summary Net resources 43 MMBbl Initial rate 17 MBbl/d, net Net capital $0.5 B F&D $11/Bbl LOE $21/Bbl (includes FPSO lease cost of $10.50/Bbl) No value assigned to natural gas Life cycle AT NPV10 $1.1 B Point forward AT NPV10 $1.8 B Upside Performance Higher initial rate 20.5 MBbl/d, net adds $45 MM of AT NPV10 * Term defined in appendix Note: Utilizing reference price case. See appendix 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 AT Cash Flow* 25.53 455.8 363.8 330.5 304.3 261.7 194.5 122.5 97.51 72.46 Cum AT Cash Flow -0.151 -0.194 -0.471 -0.585 -0.13 0.234 0.565 0.869 1.131 1.325 1.448 1.545 1.618 Investments -76 -43 -277 -140

 

15 Transferring Aseng's Learnings Ensuring success at Alen, Tamar, Leviathan and Gunflint Appraisal Disciplined appraisal program designed to address geologic complexity Planning Cohesive multi-discipline teams with cradle-to-grave approach Early concept selection with thorough regional selection process Progressing project while refining optimum design Execution Team up with industry leading contractors to leverage knowledge, cost and schedule Optimize scheduling of drilling rigs, subsea equipment, surface equipment and installation vessels Integrate win-win incentive programs Transparent communication with partners, government and contractors Emphasis on safety as baseline of successful projects Ownership of cost and schedule with all stakeholders

 

16 Alen Field Layout Designed as regional gas hub Platform water depth 238 ft. 40 MBbl/d liquid handling 440 MMcf/d gas reinjection 50,000 hp of compression Deck lift weight 11,400 tons Quarters for 84 people

 

17 Alen Project Liquid-rich development Project Sanctioned December 2010 Operated by NBL with 44.7% WI, post unitization On Schedule for First Production in 4Q 2013 Initial rate 37 MBbl/d gross, 20 MBbl/d net Resource Estimate Increased to 264 MMBoe Gross 83 MMBoe, net (34 MMBbl liquids) Implementing Proven Aseng Project Philosophy Conducted a Thorough and Efficient Appraisal Program Performed Compositional Modeling to Maximize Recovery All Major Contracts Awarded, Development Drilling in Progress Provides Hub for Future Gas Monetization

 

18 Alen Drilling and Subsurface Plans Maximizing reservoir productivity 34 MMBbl Net Liquid Resources 295 Bcf net gas resources High Deliverability Reservoir Avg. permeability 2 darcy Avg. porosity 25% Able to Increase Liquids Recovery Optimize placement of the 3 producers, 3 gas injectors Utilize gas-cycling to inject downdip and produce updip Preparing for Future Gas Sales Platform Producer Gas Injector

 

19 Alen Project Wellhead jacket installation complete Wellhead jacket installed Wellhead platform under construction

 

20 Alen Development Timeline On schedule and on budget First Production Hookup and Commissioning Subsea Infrastructure and Delivery Development Drilling and Completions Wellhead Module and Central Production Platform Wellhead Jacket Project Sanction Plan of Development and FEED Work 2011 2012 2013 Project Phase 2010 Platform Transportation, Installation Today

 

21 2013 2014 2015 2016 2017 5.217 16.132 13.953 12.175 10.611 MBbl/d Net Crude Oil Production Alen Production Early liquids production with gas-cycling

 

22 Alen Economics Strong cash flow contributor Economics Summary Net resources 34 MMBbl Initial rate 37 MBbl/d gross, 20 MBbl/d net Net capital $0.7 B F&D $21/Bbl LOE $8.50/Bbl No value assigned to natural gas Life cycle AT NPV10 $0.7 B Point forward AT NPV10 $1.1 B * Term defined in appendix Note: Utilizing reference price case. See appendix 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 AT Cash Flow* 174 526 313 275 243 170 137 108 Cum AT Cash Flow -0.042 -0.154 -0.474 -0.736 -0.66 -0.133 0.18 0.455 0.697 0.867 1 1.112 Investments -42 -113 -319 -262 -98

 

23 West Africa - Exploration Replenished inventory of high-quality prospects Superior Knowledge in the Douala Basin 1.5 MM gross acres largely under-explored Extensive seismic coverage Continuing to Mature Deeper Oil Opportunities Net Unrisked Resources of 448 MMBoe in Douala Basin Current Activity Carla - recent discovery Bwabe - drilling Future Drilling Plans 1 - 2 exploration wells per year Cameroon Block O Block I YoYo Mining License Tilapia PSC

 

24 Next Developments Production growth enhances value Diega Five wellbores encountered oil and gas Gross resource range 45 - 110 MMBoe, 60% liquids Carla Discovery below Alen field Gross resource range 35 - 100 MMBoe, 80% liquids Subsea Tieback to Aseng Production Growth 2015 and Beyond Next Steps... Finalizing appraisal design program Evaluate regional development scenarios High grade early concept designs Block O Block I

 

25 West Africa Production Outlook Doubling liquids production in three years 1/1/2010 1/1/2011 1/1/2012 1/1/2013 1/1/2014 1/1/2015 1/1/2016 1/1/2017 Alba Liquids 19.9 19.7 18.1 18 14.7 13.3 14.4 12.7 Aseng 1.2 17.1 17 15.2 14.1 12.1 9.3 Alen 5.1 16.2 14 12.2 10.6 Diega 2.1 4 3.25 MBbl/d Net Liquids Production* * Excludes Alba gas and recent Carla discovery

 

26 Regional Gas Monetization Outlook Developing LNG options with governments Approximately 4 Tcf of Gross Natural Gas Resources to Monetize NBL Leading Effort to Create LNG Export Hub in EG Low cost expansion of existing plant Evaluation of available alternatives due YE 2011 SNH / GdF Suez Studying Feasibility of LNG Plant in Cameroon Current phase of study will conclude early 2012 Significant Production and Value Impact in Second Half of Decade

 

27 West Africa High-impact core area Leading Operator in the Douala Basin Liquid Projects Producing 46 MBbl/d and Generating ~$1.2 B of AT Annual Cash Flow by 2014 Point forward AT NPV10 of $2.9 B (Aseng and Alen only) Liquid production more than doubles over next two years Project Management Skills Rank Among the Best within the Industry Developing a Plan to Monetize Existing Natural Gas Reserves Exploration Inventory Expanding with Recent Geoscience Work Exploration Drilling Ongoing in Both Cameroon and EG

 

Rodney Cook SVP International Eastern Mediterranean

 

2 Eastern Mediterranean A new global gas basin unveiled Best-in-class Operations Providing Reliable Gas Supplies to Israel Tamar Development Rapidly Progressing Leading Operated Position in the Greater Levant Basin Significant additional potential Pursuing LNG Export Options

 

3 Eastern Mediterranean Existing asset position Net Discovered Resources over 8.5 Tcf 1.7 Tcf booked reserves (Tamar) Production, Development Base Mari-B continues to produce with high reliability Noa development adds deliverability in 2H 2012 Tamar on schedule Appraising Leviathan Cyprus A Drilling NBL Operates 2.5 MM Gross Acres in Levant Basin Leviathan 40% WI Tamar 36% WI Dalit 36% WI Noa 47% WI Receiving Terminal 47% WI Mari-B 47% WI Cyprus 70% WI

 

4 Existing Pipeline Planned Pipeline Mari-B Field Reliable and low cost operations Safe, Reliable Operations Nearly 100% reliability since startup in 2004 Sales Driven by Market Demand Record daily, quarterly and annual sales in 2011 Outstanding Field Performance ~750 Bcf produced to-date Low-cost Structure LOE $0.21/Mcf, DDA $0.38/Mcf Provides Future Operational Flexibility Strategic storage facility Benefits for Israel Over $7 B in energy cost savings since 2004 CO2 emissions reduced by ~17 MM metric tons

 

5 Mari-B Sales Deliverability Late life decline partly offset with Noa Note: Forecast assumes no curtailment of maximum production at Mari-B Gross Capacity MMcf/d Mari-B wells 9 and 10 Online Compression Noa Online Tamar Online Mari-B wells Decline

 

6 Tamar Field Layout Phase 1 maximum deliverability of 1 Bcf/d Tamar Mari-B 5 Subsea Wells Gas Injection at Mari-B for swing sales

 

7 Tamar Project Moving ahead on an accelerated timeline Project Sanctioned in 2010 Operated by NBL with 36% WI Adjusted for a Change to the Onshore Delivery Point Remains on Schedule and on Budget All Major Contracts Awarded and Numerous Activities in Progress Resource Estimate Continues to Increase Now 9 Tcf gross mean, 2.8 Tcf net Commissioning Late 2012 First sales expected April 2013 2.5 years from sanction and 4 years from discovery

 

8 Tamar Subsurface Update Resource estimate growing with development Mean Resource Estimate Grows from 8.4 Tcf to 9.0 Tcf Appraisal drilling Petrophysical analysis Initial Development 6.5 Tcf Gross, 2 Tcf Net Reserves booked to-date 5.4 Tcf gross, 1.7 Tcf net Superior Quality Reservoir Clean sand with permeability 1 darcy and porosity 25% Excellent lateral and vertical connectivity Completions able to flow 250 MMcf/d

 

9 Tamar Development Progress Delivering a world-class project Over 3.6 MM Man Hours with Best- in-class Safety Record No major accidents, TRIR of 0.16 Project Activity Jacket fabrication 50% complete Platform deck 53% complete Pipe lay 55% complete Onshore facility expansion underway Spare Key Equipment Purchased to Avoid Critical Path Disruption to Schedule Transferring Aseng's Learnings and Best Practices

 

10 Tamar Project Schedule Progressing as planned First Production Platform Installation Subsea Infrastructure and Delivery Drilling and Completions Mari-B Brownfield Project Sanction 2011 2012 2013 Project Phase 2010 Platform Construction Onshore Terminal Modification Hookup and Commissioning Today

 

11 Tamar Gas Sales Underpinned by a growing gas market Growing Israel Domestic Gas Demand 1,440 MW of Coal-fired Power Conversion to Natural Gas Already Announced Potential for ~1 Bcf/d of incremental demand by converting coal-fired generation to gas In Final Stages of Negotiation with Israel Electric In Active Discussions with Existing and New Customers Multiple independent power producers Industrials Cogeneration

 

12 Israel Gas Demand Outlook Robust growth outlook with significant upside potential Base Demand Growth Driven by Power Generation and Industrials Potential for Converting Coal-fired Power Generation to Gas Source: Poten and Partners, Israel MNI, Israel Electric, NBL analysis Annual Average Natural Gas Demand 10% CAGR Swing Demand MMcf/d

 

13 Tamar Phase 1 Economics Significant value creation Summary Economics Net reserves 2 Tcf Production plateau over 15 years Net capital $1.1 B F&D $0.60/Mcf LOE $0.30/Mcf 2013 2014 2015 2016 2017 2018 2019 2020 361 651 718 900 900 900 900 900 2004 2005 2006 2007 2008 2009 2010 3Q11 2.71 2.68 2.72 2.79 3.1 3.47 4.03 5.15

 

14 Leviathan Project World's largest offshore gas discovery in 2010 Discovered YE 2010 NBL operated with 39.66% WI Third Successful Test of Tamar Sand Reservoir in Basin High Quality Reservoir Clean sand with 500 millidarcy permeability and 21% porosity Resource Estimated at 16 Tcf Gross, 5.6 Tcf Net Giant Reservoir Spans Area of 24 GOM OCS Blocks Drilling #3 Appraisal Well

 

15 Project and Commercial Teams in Place Developing Commercialization Options Israeli domestic market Evaluating early production scenarios Exports via LNG or pipelines Screening Field Development Concepts Subsea tieback to shallow water platform Semi-submersible FPSO Floating LNG Incorporating Tamar and Aseng Learnings Leviathan Discovery Evaluating development options

 

16 Eastern Mediterranean Exploration Leading acreage position in an emerging basin Significant Remaining Exploration Potential 12 prospects identified in Tamar sands with unrisked potential over 20 Tcf gross 3.7 BBoe gross unrisked potential in deep oil play Current Activity Cyprus A - drilling Dolphin - small discovery Future Drilling Plans Continue to test Tamar sand prospects Re-enter Leviathan #1 to test deep oil concept Leviathan 40% WI Tamar 36% WI Dalit 36% WI Cyprus 70% WI Dolphin 40% WI

 

17 Post Japan Earthquake / Tsunami Resulting in Increase in Global Gas or LNG Demand Gas to substitute for nuclear power Asia Pacific will pull available LNG supplies to meet incremental demand Global LNG Demand Growth Source: Poten & Partners Increase in Future Global LNG Demand Leviathan-sized resource is needed by 2020 Bcf/d 25 30 35 40 45 50 2010 2012 2014 2016 2018 2020 2010 projection 2011 projection Bcf/d Australia & PNG Other EMed Global LNG Capacity

 

18 Eastern Mediterranean LNG Natural gas export options look encouraging Compelling Case for Natural Gas Exports Government revenues Existing discovered resources exceeds projected domestic needs Additional exploration potential remains Anticipation of export potential will encourage more exploration Pre-FEED Studies of LNG Export Options Underway Multiple sites being evaluated Expected to finish by March 2012 Continue to Assess and Quantify Natural Gas Resources Advisor to Assist in Screening Strategic Partners EGYPT TURKEY SYRIA LEBANON JORDAN ISRAEL CYPRUS LNG LNG LNG Egyptian LNG SEGAS LNG Floating LNG Existing LNG Facilities Potential LNG Facilities

 

19 Eastern Mediterranean World-class portfolio and potential Mari-B Continues to Reliably Supply Local Natural Gas Markets Over 8.5 Tcf of Net Resources Discovered Tamar Development on Track for Commissioning Late 2012 Forecasted Israel Natural Gas Base Annual Demand Growth of 10% with Significant Upside Multiple Prospects and Leads Provide Exploration Upside LNG to Provide Substantial Growth in Second Half of the Decade

 

20 International Production Outlook Over a decade of underpinned growth 2012 - 2016 Capital $6.4 B 15% CAGR Over Next Decade from Current Assets and Existing Discoveries* * Excludes Alba LNG Gas, Carla and Cyprus 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 Base 61.5 57.6 42.4 25.5 21.8 21.3 17.3 14.7 12.5 10.2 8.2 Development 1.1 18.7 45.9 65.8 73.5 98.5 116.5 117.2 116.9 119.3 120.6 Export Gas 38.9 95.3 124.4 125.5 14% CAGR 16% CAGR Net Production* West Africa Eastern Med Other Capex 2.54 3.45 0.36 West Africa New Ventures Other Eastern Med

 

Exploration Susan Cunningham SVP Exploration and Business Innovation

 

2 Noble Energy Exploration Leading explorer in the industry The Drivers of Our Success The Results of Our Efforts Greater Potential in the Next Five Years It's repeatable It's sustainable

 

3 Exploration and Geoscience Excellence Drivers of our success Focused on Identifying Impactful Opportunities with Running Room Applying leading edge technologies throughout program lifecycle Recruiting and retaining high-quality talent Leveraging exploration success Designed Disciplined Processes for Objective Assessment of Risk / Reward New ventures assessment Exploration evaluation Appraisal process Combining Objectivity with Intuition Learning and training our intuition Recognizing when something 'doesn't feel right' despite objective assessments Seeing the possibilities of innovation and extraordinary thinking

 

4 NBL Results Over the Last Five Years Exploration process yielded significant discovered resources Discovered Nearly Two BBoe ~2 times 2010 reserves ~25 times annual production Tripled Resource Inventory to Over Nine BBoe Net Unrisked Created Two Core Areas Through Exploration 2006 2007 2008 2009 2010 Finding Costs 3.88 2.73 2.98 1.07 0.57 Resources Found 48 213 267 378 1030 Resources Found (MMBoe) Finding Costs ($/Boe)

 

5 Exploration Success Outperformed peers and super majors from 2006 ^ 2010 Low Finding Cost Moving Resources to Production Quickly ~35% of Expected Production in 2021 Will be from Discoveries Made from 2006 - 2010 Source: Wood Mackenzie 0.25 4.57 1 0.42 3.09 1 0.31 3.13 1 0.41 5.43 1 0.31 0.97 1 0.45 2.62 1 0.44 2.21 1 0.51 0.79 1 0.76 0.55 1 0.35 1.54 1 0.32 1.2 1 0.44 1.53 1 0.4 2.01 1 0.43 0.68 1 0.52 1.05 1 0.5 5 4 Exploration Peer Group Super Major Noble Energy, Inc. Success Rate Finding Costs ($/Boe)

 

6 North America Onshore Exploration Converting ideas into core areas Strategy Focus on liquid-rich unconventional resource plays Leverage learnings, skill sets and best technical practices Early technical investment in exploration to maximize value and identify the sweet spot Investment decisions influenced by global portfolio view What We Did DJ Basin 2006 - 2011: Doubled acreage position, drilled 21 exploration wells 2012 plans: Niobrara play running room, 20 exploration wells Leasing in new oil resource plays Inventory Growth Over Past Five Years Acquired 1,800 sq. mi. 3D seismic 83% increase in unrisked resources since 2006 Exploration Potential Net unrisked resources of 1.6 BBoe Greater than 50% liquids Leasing in 3 emerging new ventures plays 200,000 acres leased to-date

 

7 Goshen DJ Basin Defining the sweet spot in the Niobrara What We Did Acquired over 1,700 sq. mi. of 3D seismic Cut over 3,400 ft. conventional core Drilled exploratory horizontal programs outside of Wattenberg Doubled acreage position What We Know Rock properties variable across basin Multiple Niobrara pods outside of Wattenberg field have varying potential and fracture characteristics Requires an exploration completions strategy Exploration Potential Approximately 380 MMBoe net unrisked resources (over multiple potential targets)

 

8 Deepwater Gulf of Mexico 2006 Moving to impact opportunities What it Looked Like Four discoveries, two producing Exploited subsea tieback portfolio Amplitude play was 50% of inventory Narrow Azimuth 3D What We Knew Subsalt imaging technology improving High-quality Miocene reservoirs More sand than anticipated Miocene subsalt is a place for growth Lorien Ticonderoga Raton Swordfish Net Unrisked Mean Resources (MMBoe) 2006 Pg

 

9 2006 2011 Deepwater Gulf of Mexico 2011 Integrating technologies and knowledge is the key What We Did Doubled technical staff Grew subsalt inventory Amplitude play is 25% of inventory Moved to wide azimuth 3D Proprietary reprocessing Ramped up regional work during moratorium Focused on Miocene, not Lower Tertiary Galapagos discoveries in excess of 100 MMBoe gross 65% success rate in subsalt What We Know Depth imaging revealing next generation of subsalt traps Knowledge of reservoir and trap risk grown dramatically Exploration Potential Building pre-Miocene portfolio Gross resource exposure ~2.5 x 2006 Grew prospect inventory by 150% WAZ 3D Raton South Gunflint Galapagos Discovery Net Unrisked Mean Resources (MMBoe) Pg

 

10 Blind Faith Field ~ 100 MMBOE Thunderhorse Basin Salt Middle Miocene 18300 18100 Deepwater Gulf of Mexico 2012 ^ 2014 program candidates Amplitude Prospect 55% WI Water depth 7,200 ft. Pg 54% P75 - P25: 20 - 60 MMBoe gross resources Multiple Subsalt Options Rigorously working maturation of subsalt opportunities Exploiting Remaining Amplitude Plays 2 Ready for 2012 drilling Subsalt Prospect 100% WI Water depth 6,600 ft. Pg 36% P75 - P25: 55 - 275 MMBoe gross resources S. Het This area intentionally left blank. This area intentionally left blank.

 

11 International Where's the next game-changer? Strategy Focus on high-impact game-changers Leveraging core competencies and learnings Execute superior evaluation process Ability to operate Plan for success What We Did Expanded in Israel and Equatorial Guinea Set up new ventures group Entered Cyprus, Cameroon, Surinam India, France and Senegal Exited North Sea and China exploration, Suriname and India Inventory Status Doubled Inventory of prospects More than tripled resources Net unrisked resources of 5.6 BBoe Average prospect 280 MMBoe International Portfolio 2011 2006 MMBoe Pg

 

12 Eastern Mediterranean 2006 1 TCF discovery but limited exploration potential What it Looked Like Sales from first commercial gas discovery (Mari-B) began in 2004 Farmed into Tamar and Dalit concessions mid year 2006 Previous operator exited What We Knew Biogenic gas above salt in Mari-B Reservoir and source below salt unknown One large high-risk opportunity in unproven basin (Tamar) Noa Mari-B Tamar Dalit

 

13 Eastern Mediterranean 2011 "More gas than we dreamed of.... oil to be tested" What We Did Captured acreage for running room Acquired proprietary 2,450 mi. of 2D and 2,500 sq. mi. 3D seismic 25 Tcf discovered in three prospects What We Know High-quality reservoirs Biogenic gas above and below salt Evidence of deep petroleum system Running room is real Exploration Potential Undiscovered Tamar sand potential over 20 Tcf in 12 prospects Prospects (excluding Cyprus A) range from 0.7 to 3.5 Tcf each Deep oil potential of 3.7 BBoe Other plays being evaluated Deep Oil Prospects Tamar Sand Prospects

 

14 Cyprus A Prospect Largest prospect currently being drilled Summary First well offshore Cyprus NBL operated with 70%* WI 5,500 ft. water depth P75 - P25: 3 - 9 Tcf gross resources 60% probability of success Results impact other leads currently being evaluated 3D Prospects Discoveries *Pending assignment Cyprus A Tamar Dalit Cross section (Displayed above) Leviathan

 

15 Tanin Prospect To be drilled in the Alon A lease, Israel Pre-drill Summary NBL operated with 47% working interest 5800 ft. water depth P75 - P25: 0.8 - 1.2 Tcf Gross Resources 55% probability of success Additional upside possible in area, dependant upon well results Tanin-1 Tanin This area intentionally left blank.

 

16 Offshore France Building on Eastern Mediterranean knowledge Large Inventory of Structural Prospects and Leads in Rhone Maritime Block Evidence of Potential Gas Reservoirs Final Processing Still to Come Possible 3D Seismic in 2012 Summary NBL operated with 72.5% WI 5,200 - 8,500 ft. water depth 2.8 MM gross acres This area intentionally left blank.

 

17 West Africa - Douala Basin 2006 High risk stratigraphic play with running room What it Looked Like No nearby wells Belinda gas discovery What We Knew Virtually unexplored basin east of Bioko Island Unproven hydrocarbon basin AVO supported prospects Excellent deepwater sand reservoir Play potentially extended into Cameroon Cameroon

 

18 West Africa - Douala Basin 2011 Multiple discoveries - significant oil potential What We Did Shot 825 sq. mi. 3D Reprocessed 2,285 sq. mi. 3D Established acreage position in Cameroon 6 significant discoveries Created a core area What We Know Stratigraphic traps prolific Multiple productive, high-quality reservoirs Oil source rock Upside for liquids 305 MMBoe net resources discovered Exploration Potential 13 prospects and leads in multiple plays 448 MMBoe net unrisked resources Prospect size ranging from 50 - 390 MMBoe Cameroon Block O Block I YoYo Mining License Tilapia PSC

 

19 Carla Discovery Expanding West Africa development portfolio Summary AVO supported target below Alen field Drilled to a depth of 11,500 ft. with deepening of Alen development well Encountered oil in high-quality Upper Oligocene interval sands filled to base of sand NBL operated with 51% WI 1,900 ft. water depth P75 - P25: 35 - 100 MMBoe gross resources Carla Alen Block O This area intentionally left blank.

 

20 Cameroon - Bwabe Prospect Largest oil prospect to-date Pre-drill summary Amplitude supported Oligocene oil target NBL operated with 50% WI 1,800 ft. water depth 100+ MMBoe gross resources 25% probability of success Information gained will impact other prospects and leads

 

21 Bouma Prospect West Africa Exploration Pre-drill Summary AVO supported target Prospect identified from newly acquired Cameroon 3D seismic NBL operated with 50% WI 1,600 ft. water depth P75 - P25: 95 - 400 MMBoe gross unrisked resources 35% probability of success Cameroon Tilapia PSA Bouma This area intentionally left blank.

 

22 Offshore Nicaragua World-class opportunity What We Did Shot 3,050 mi. of proprietary seismic Conducted high-quality technical interpretation What We Know 2 MM gross acres NBL operates with 100% WI; seeking partner(s) Similar to 500 MMBoe Malampaya field (Philippines) Model indicates oil potential Multiple play types Exploration Potential >1.3 BBoe mean resources Multiple prospects and leads Multiple play types Central America Nicaragua Tyra 100% WI

 

23 Tyra Central Bank Prospect The reason we acquired the acreage Pre-drill Summary Carbonate reef build-up target NBL operated with 100% WI 1,300 ft. water depth P75 - P25: 100 - 1,000 MMBoe gross resources 20% probability of success Nicaragua Isabel 110 km Tyra Modern Analogue This area intentionally left blank.

 

24 Exploration Performance 2006 - 2011 Leading explorer in the industry Source: Wood Mackenzie Finding Cost ($/Boe) Exploration Peer Group Super Major Noble Energy, Inc. Proportionally Finding More at Lower Cost than the Competition

 

25 Exploration and Geoscience Excellence We Found It Discovered 2 BBoe at very low cost We are Developing It Rapid discovery to production Executing on time and on budget We are Ready for the Future More than tripled inventory in 5 years Active global 'new ventures' program And Still Building Focus, discipline and excellence BBoe Excludes proved and discovered resources Net Exploration Resource Inventory 2006 2011 Risked 975 2930 Unrisked 2668 9212 2006 2011

 

Closing Remarks / Q&A Chuck Davidson Chairman and CEO

 

2 Noble Energy Capitalizing on success - driving multi-year value creation Strong and Diversified Portfolio Five core areas - all growing rapidly Deep inventory of investment opportunities Sustainable Industry-leading Exploration Organizational Capability to Execute Robust Financial Framework Highly Transparent Path Towards Value Creation Noble Energy: Energizing the World, Bettering People's Lives

 

 

Appendix

 

2 2 Price Assumptions

 

3 Defined Terms Defined Terms