1. The “Shale Revolution” Myths and Realities Trans-Atlantic Energy Dialogue Washington, DC December 10, 2013 J. David Hughes Global Sustainability Research Inc. Post Carbon Institute 1

2. Conventional Wisdom The United States is on the verge of Energy Independence thanks to the “SHALE REVOLUTION”. Shale Gas production will continue to grow for the foreseeable future (2040 at least) and prices will remain below $4.50/mcf for the next 10 years and below $6.00/mcf for the next 20 years. The way is clear for U.S. LNG exports to monetize the shale bounty. Large scale LNG exports of shale gas from Canada will provide a bonanza. Tight Oil will allow U.S. production to exceed that of Saudi Arabia and U.S. imports will shrink to zero. © Hughes GSR Inc, 2013 2

3. U.S. Natural Gas Supply Projection by Source, 2010-2040, EIA Reference Case 2013 Canadian Imports Shale Gas (+105% 2012-2040) Coalbed Methane 50% of 2040 Production 55% increase in production by 2040 Tight Gas Conventional Offshore Associated Alaska U.S. domestic consumption Exports (data from EIA Annual Energy Outlook 2013, Tables 13 and 14, http://www.eia.gov/forecasts/aeo/er/excel/yearbyyear.xlsx)http://www.eia.gov/forecasts/aeo/er/excel/yearbyyear.xlsx © Hughes GSR Inc, 2013 3

4. Shale/Tight Oil Lower-48 Offshore Alaska Lower-48 Onshore Conventional Production Onshore EOR 32% of 2040 Supply U.S. Crude Oil Production Projection by Source and Region 2010-2040 (EIA 2013 Reference Case) (data from EIA Annual Energy Outlook 2013, Table 14, http://www.eia.gov/forecasts/aeo/er/excel/yearbyyear.xlsxhttp://www.eia.gov/forecasts/aeo/er/excel/yearbyyear.xlsx Peak Production 2019 © Hughes GSR Inc, 2013 (data from EIA Annual Energy Outlook 2013) 4

5. Contributions to Global Oil Production Growth 2013-2035 (IEA World Energy Outlook 2013) © Hughes GSR Inc, 2013 (IEA World Energy Outlook 2013) Tight Oil more than doubles from current levels by 2025 then declines to current levels by 2035 Light Tight Oil 5

6. U.S. Shale Gas Production from EIA data, 2007 - June, 2013 (data from DI Desktop, HPDI, September, 2012) © Hughes GSR Inc, 2013 (data from EIA, 2013, http://www.eia.gov/naturalgas/weekly/img/ShaleGas-201306.xlsx)http://www.eia.gov/naturalgas/weekly/img/ShaleGas-201306.xlsx 42% of U.S. Production Peak Excluding Marcellus and tight oil plays occurred November 2011 Now Down 12% Marcellus Haynesville Barnett Eagle Ford 6

7. Tight Oil, NG Liquids and Conventional Production from Six Plays, 2007- June, 2013 (EIA DPR Report, 2013) © Hughes GSR Inc, 2013 (data from EIA DPR report December, 2012) Eagle Ford Bakken Permian Basin 7

8. Tight Oil Production from Six Plays, 2007- June, 2013 (EIA DPR Report, 2013) - Excludes NGLs and Conventional © Hughes GSR Inc, 2013 (data from EIA DPR report December, 2013) Eagle Ford Bakken 8

9. (Data from EIA updated to September, 2011; http://www.eia.gov/oil_gas/rpd/shale_gas.jpg )http://www.eia.gov/oil_gas/rpd/shale_gas.jpg 9

10. U.S. Shale Gas Production by Play – June 2013 (data from EIA current to June, 2013) Top 3 Plays = 68% of Total Top 6 Plays = 92% of Total © Hughes GSR Inc, 2013 10

11. U.S. Tight Oil Production by Play – June 2013 (data from EIA current to June, 2013 – excludes NGLs and conventional production) Top 2 Plays = 74% of Total Top 4 Plays = 85% of Total © Hughes GSR Inc, 2013 11

12. The Shale Play Life Cycle Discovery followed by leasing frenzy. Drilling boom follows to meet “held-by-production” lease requirements. Sweet spots identified, targeted and drilled off. Production rises rapidly and is maintained for cash-flow despite potentially uneconomic full-cycle costs. Sweet spots become saturated and well quality and field production decline. Plays like the Haynesville become middle aged after just five years. © Hughes GSR Inc, 2012 12

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14. Haynesville Gas Production and Number of Operating Wells, 2006-2013 (data from DI Desktop, HPDI, September, 2012) © Hughes GSR Inc, 2013 (data from DrillingInfo/HPDI, July, 2013, three month trailing moving average) Peak January 2012 14

15. Haynesville Type Gas Well Decline Curve (data from DrillingInfo/HPDI, March, 2013) Yearly Declines First year = 66% Second year = 49% Third year = 41% Fourth year = 49% © Hughes GSR Inc, 2013 3-Year Decline = 89% 15

16. Overall Field Decline for Haynesville Gas Production based on Production Decline from pre-2012 Wells (data from DI Desktop, HPDI, September, 2012) Overall Field Decline = 47% © Hughes GSR Inc, 2013 (data from DrillingInfo/HPDI, March, 2013) 16

17. Type Gas Well Decline Curves for Top Five Shale Gas Plays Constituting 81% of Shale Gas Production (data from Drillinginfo, March, 2013) 3-Year Decline Haynesville = 89% Marcellus = 79% Barnett = 79% Fayetteville= 80% Woodford = 77% © Hughes GSR Inc, 2013 Average 3-Year Decline = 84% 17

18. Overall Field Decline for Top Five Shale Gas Plays based on Production Decline from pre-2012 Wells (data from DI Desktop, HPDI, September, 2012) Field Decline (per year) Haynesville = 47% Marcellus = 29% Barnett = 28% Fayetteville = 35% Woodford = 44% © Hughes GSR Inc, 2013 (data from Drillinginfo, March, 2013) Average Field Decline = 37% 18

19. Shale Gas Production from Top Five Plays Constituting 81% of U.S. shale gas production, 2006 - 2013 (data from DI Desktop, HPDI, September, 2012) © Hughes GSR Inc, 2013 (data from Drillinginfo, July, 2013, three month trailing moving average) 19

20. Shale Gas Production from Top Five Shale Gas Plays Constituting 81% of Production, 2006-June, 2013 © Hughes GSR Inc, 2013 (data from DrillingInfo, October, 2013, three month trailing moving average) Haynesville Barnett PA Marcellus 20

21. Other (data from Baker-Hughes, November, 2013) © Hughes GSR Inc, 2013 U.S. Gas Rig Count by Basin, 2011-2013 Barnett Marcellus 61% 24% 15% Falling Rig Count will cut Production and put pressure on Price once inventory of Drilled-but-not-connected Wells is worked off 21

22. Sweet Spots are Key to Understanding the Evolution of Shale Plays 22

23. Horizontal Well Quality Trends – Top Five Shale Gas Plays (data from DI Desktop, HPDI, September, 2012) © Hughes GSR Inc, 2013 (data from Drillinginfo, March, 2013) Fayetteville – Early Middle Age Barnett – Middle Age Haynesville – Late Middle Age Woodford – Early Old Age 23

24. Other (data from Baker-Hughes, November, 2013) © Hughes GSR Inc, 2013 U.S. Oil Rig Count by Basin, 2011-2013 Permian Basin Eagle Ford 40% 33% 14% 13% 24

25. Bakken/Three Forks Oil Production and Number of Operating Wells, 2005- June 2013 © Hughes GSR Inc, 2013 (data from Drillinginfo, October, 2013, three month trailing moving average) 25

26. Bakken/Three Forks Type Oil and Barrels of Oil Equivalent Well Decline Curves Including Montana and North Dakota (data from Drillinginfo, October, 2013) © Hughes GSR Inc, 2013 Oil Decline First Year = 70% Second Year = 34% Third Year = 23% Fourth Year = 21% 3-Year Decline = 84% 26

27. Bakken Field Production Decline – Oil Production from all Wells Drilled Prior to 2012 © Hughes GSR Inc, 2013 (data from Drillinginfo, October, 2013) 27

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29. Bakken/Three Forks Production By County, North Dakota and Montana, June, 2013 Total Production = 787 Kbbls/day Top 2 counties = 52% of production Top 4 counties = 85% of production © Hughes GSR Inc, 2013 (data from Drillinginfo, October, 2013) 29

30. Bakken/Three Forks Type Oil Well Decline Curves by County and Region (data from Drillinginfo, October, 2013) © Hughes GSR Inc, 2013 30

31. Bakken/Three Forks Well Distribution through mid-2013 © Hughes GSR Inc, 2013 (data from Drillinginfo, October 2013) 31

32. Bakken Oil Production - Declining Drilling Rate Scenario, Risked at 80% for locations versus Unrisked, 2005-2035 © Hughes GSR Inc, 2013 (data from Drillinginfo, October, 2013) Risked Wells = 21474 Unrisked Wells = 25974 Risked total production = 4.5 billion bbls Unrisked total production = 5.0 billion bbls. Max Drilling rate = 3500 wells/y Final Drilling rate = 2000 wells/y 32

33. Bakken and Eagle Ford Oil Production – Declining Drilling Rate Risked at 80% for locations, 2005-2035 © Hughes GSR Inc, 2013 (data from Drillinginfo, October, 2013) Bakken Risked Wells = 21474 Eagle Ford Risked Wells = 37052 Bakken risked total production = 4.5 billion bbls Eagle Ford risked total production = 6.5 billion bbls. Max Drilling rate = 5500 wells/y Final Drilling rate = 3000 wells/y Eagle Ford Bakken NEED (2013 - 2026): 48,000 more Wells $450 Billion more Capex Prize: 9.5 Billion barrels (last 75% will require much higher prices) 33

34. Shale gas production in several top plays is declining and tight oil production from the top two plays is likely to peak in the 2016-2017 timeframe High well- and field-decline rates mandate sustained high levels of drilling to maintain production. Sweet spots become exhausted early on in field development hence drilling rates must continually escalate to maintain production levels. Liquids production with associated gas has allowed gas production to remain stable – for now – but long term sustainability is questionable. High quality shale plays are not ubiquitous: 68% of shale gas production comes from 3 plays. 74% of tight oil production comes from 2 plays. Environmental concerns with fracking are widespread and will likely escalate with the escalating drilling treadmill needed to maintain, let alone grow, shale gas and oil production. Shale Takeaways © Hughes GSR Inc, 2013 34