U.S. Shale Liquids Production: What Have Another 12 Months Taught Us?

Transcription

1 PIRA Energy Group U.S. Shale Liquids Production: What Have Another 12 Months Taught Us? Dr. Mark A. Schwartz President and Managing Director, Scenario Planning Annual Retainer Client Seminar New York City: October 1-11, 213

2 U.S. Shale Liquids Growth Fastest in History MMB/D U.S. Shale Liquids +3.2 MMBD in 4 Years

3 U.S. Shale Liquids Growth Nearly Unparalleled MMB/D U.S. Shale Liquids +3.2 MMBD in 4 Years MMB/D Growth Parallels?

4 Shale Crude Production Growth Dominating US Growth Outlook MB/D Growth MB/D Production Shale Lower 48* GOM Alaska NGL Total, MB/D Note: Lower 48* excludes GOM, and Shale 75 7 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

5 Major Influence on Global Non-OPEC Supply MB/D Year-on-Year Change OPEC NGL Other China Other Western Europe 5 North Sea FSU -5 Mexico -1 Canada United States

6 Arguments of Pessimists vs. Optimists Volume Optimists Early days of shale development major technology improvements still ahead Resource base still poorly understood. Ultimate potential will continue to move higher Recovery factors extremely low and will improve. Eventually enhanced recovery techniques Decline rates will be better managed Volume Pessimists Best prospects found first. Disappointments will occur beyond the core. Big technology advances captured during first decade Cumulative decline will offset growth. Tails will be truncated. Resource base is limited Bakken and Eagle Ford will prove to be unique Environmental limits will constrain growth Production growth will continue to exceed expectations Production will reach an early peak and then plateau or decline

7 Productivity Gains Reflected in Disconnect Between Rig and Production Growth U.S. Horizontal Drilling Rigs % U.SShale OiI Production (MMBOE/D) + 33%

8 Shale Will be Responsive to Price More price elastic than other oil» Relatively low upfront cost / shorter time lags» High decline rate to be offset» Short lead times from investment decision to production» More financing via cash flow / hedging production Real test will come during price downturn» Reduced activity vs. cost reduction

9 Parallels Becoming Stronger 4 35 Shale U.S. Shale Natural Gas Gas BCF/D MMB/D 7 6 Shale Liquids BCF/D Barnett Haynesville Marcellus Other Bakken Eagle Ford Permian Other NGL's

10 Similarities and Differences What is the same?» Technology» Regulatory Environment What is different?» Market share» Liquids credit for gas» Geology» Position on the cost curve

11 Market Penetration Significantly Different 45% 4% 35% 3% 25% 2% 15% 1% 5% % Shale Gas Share of North American Market Shale Liquids Share of Global Market

12 Oil Molecules Fundamentally More Difficult to Recover Oil molecules larger than gas» Factor of 6-8 for light oil Results in higher viscosity Means lower recovery factors for the same technology» 2-1% for oil vs. 2-3% for natural gas

13 Shale Has Pushed US Production to Record Highs Canadian and LNG Imports Falling BCF/D Net LNG Imports Net P/L Imports Shale Non-Shale 1

14 Conclusions US Shale growth nearly unparalleled in oil industry history» Evidence to date seems to be supporting volume optimists Annual increment may slow but nothing to suggest production is close to plateau Gas parallels mount but key differences argue against significant undermining of price Cost structure still holding

15 PIRA Energy Group U.S. Shale Liquids Production: What Have Another 12 Months Taught Us? Miriam Levy Director, Political Risk Annual Retainer Client Seminar New York City: October 1-11, 213

16 Drilling and Production Trends

17 Shale Production Was 45 MB/D Higher in June 213 Than PIRA s Model Had Predicted Last Year U.S. Shale Crude & Condensate Production (MMB/D) October 212 Forecast Bakken Permian Basin Shales Eagle Ford Other

18 Bakken Performed as Expected; Eagle Ford Productivity Gains Surprised to the Upside Bakken Production (MB/D) Eagle Ford Production (MB/D) 1, , , Oct 212 Forecast 1, Oct 212 Forecast 8 Oct 213 Actuals 8 Oct 213 Actuals (2) (2)

19 How to Assess Trends? Analyze all assumptions holistically Examining one in isolation can lead to incorrect conclusions about future trends Model inputs Rig count Drilling efficiencies Well productivity Costs Resource base Prices

20 Horizontal Oil Rig Count Flat in 213, But Production Growth Accelerated 1, , 2,5 2, 1,5 1, 5 Horizontal Oil Rigs +25 (211) +2 (212) +1 (213 YTD) U.S. Shale Crude & Condensate Production (MB/D) +7 (211) +835 (212) +845 (213 YTD)

21 Rig Growth Trends Vary by Play: Bakken Down, Eagle Ford Up Horizontal Rig Count Y/Y Growth (Sep-13 v. Sep-12) 4 +25% % +35% 1 5 (1) (2) (3) (4) -18% -7% Other Midcon Permian Bakken Niobrara Eagle Ford

22 Operators Reduced Drilling Times 3%-4% Bakken Days Spud to Total Depth Eagle Ford Days Spud to Total Depth 3-5% % % Q11 2Q12 2Q13 2Q11 2Q12 2Q13 Estimated based on quarterly operating reports from major producers in each play.

23 Implications for Production Growth Rate Bakken Eagle Ford v v. 12 Rigs 2 17 (15%) % Drill Days Wells per Year 25 2, ,88 (36%) 33% 15 3, ,21 (33%) 65%

24 Initial Production Rates Per Well Are Declining Despite Continued Production Growth 7 6 Bakken 3-Day IP (BOE/D) 8 7 Eagle Ford 3-Day IP* (BOE/D) Gas Oil *Using single-well leases as reported to the Texas Railroad Commission.

25 Bakken Type Curve Shape Relatively Stable Since 21 6 Bakken Average Single-Well Production Profile (BOE/D) PIRA MODEL Months

26 Decline Rates in Eagle Ford Are Less Consistent But It Is a Younger Play Eagle Ford Average Single-Well Production Profile* (BOE/D) PIRA MODEL Months *Average calculated using single-well leases as reported to the Texas Railroad Commission.

27 Well EURs Are Trending Higher, According to Operators Operator-Reported Predicted Well EUR in Bakken (MBOE) 1, Q11 2Q12 2Q13 Continental Hess EOG Marathon Production-Weighted Avg Due to lack of sufficient historical data, PIRA cannot independently verify predicted well EURs.

28 Operators Are Optimizing Completion Techniques to Maximize Returns Longer laterals More use of 3D seismic analysis Completion technique Type of frac (slickwater, gel) Number of frac stages Frac design (zipper fracs, clustered perforations) Proppant content Higher horsepower fracturing/larger fracs Tighter well spacing Ex. 64 acres in Bakken

29 Implications for Production Growth Rate and Overall Acreage Recovery Bakken Eagle Ford v v. 12 Rigs 2 17 (15%) % Drill Days (36%) 15 1 (33%) Wells per Year 2,92 3,88 33% 3,772 6,21 65% Well Spacing (5%) 8 5 (38%) Wells per 12,8 Acres EUR (MBOE) EUR (MBOE) / 12,8 Acres , ,4 1% 22% 143% , ,4 6% (11%) 42%

30 Well Costs Are Decreasing Slightly, And Range Is Narrowing 14 Range of Reported Well Costs* ($MM) Bakken Eagle Ford 4 2 2Q11 2Q12 2Q13 *Drilling and completion cost for a single well, estimated based on quarterly operating reports from major producers in each play.

31 Net Effect on Breakeven Costs Is Mixed Oct-13 LLS Basis Oct-12 LLS Basis Bakken Breakeven Costs ($/Bbl) Eagle Ford Wet Gas Oct-13 Wellhead Oct-12 Wellhead Eagle Ford Oil *Single-well breakeven cost calculations include drilling and completion costs; royalties; severance taxes; PIRA s oil, natural gas, and NGL price forecasts; and a 1% return. Calculations do not include land acquisition costs or any operator overhead.

32 Historically High Forward Price Discount Creates Incentive to Produce Now 3 2 Prompt 5-Year-Deferred WTI ($/Bbl) U.S. Shale Crude & Condensate Production (MMB/D) 1 (1) (2) (3) (4)

33 *Includes production from the Barnett, Brown Dense, Granite Wash, Mississippi Lime, Monterey, Niobrara, Tuscaloosa Marine, Uinta, Utica, and Woodford formations. Shale Oil Forecast Peaks in 226 at 6.6 MMB/D With 8% from Bakken, Eagle Ford, and Permian 7 U.S. Shale Crude & Condensate Production (MMB/D) Other* Eagle Ford Permian Shales Bakken

34 Since Last Year, Shale Forecast Revised Up And Peak Moved Earlier U.S. Shale Crude & Condensate Production (MMB/D) Revisions v. October Oct 213 Oct 212 Oct

35 Upside And Downside Risks to U.S. Shale Production Forecast Upside Risks Further efficiency gains in existing plays Application of associated technologies to conventional production More plays with liquids potential discovered (larger resource base) Enhanced recovery techniques Significant export of U.S. crude allowed Downside Risks Increased regulation Cost escalation (input shortages) More rent collection Insufficient midstream capacity expansion Lack of Canadian access to west coast for export Smaller resource base Price

36 Have We Reached the Peak Of the Learning Curve? Tremendous learning curve over the past four years driving historically rapid production growth Have the efficiency and productivity gains peaked? PIRA believes production growth will slow as future efficiency gains offset lower-quality resources BUT: Geology outside main plays largely unproven No significant cost pressures yet Technology is still relatively new Tail behavior of wells is unknown only 5-7 years of history! Since every play is different, newer plays are likely to experience similar productivity gains in first few years of development

37 PIRA Energy Group U.S. Shale Liquids Production: What Have Another 12 Months Taught Us? Glenn Schwartz Senior Analyst, Emissions and Clean Energy Annual Retainer Client Seminar New York City: October 1-11, 213

38 Fracking Regulation Discussion

39 Potential Environmental Impacts of Fracking Stress on surface/ground water supplies due to withdrawal of large volumes. Mining of sand.

40 Potential Environmental Impacts of Fracking Stress on surface/ground water supplies due to withdrawal of large volumes. Mining of sand. Air pollution from release of VOCs, NOx, HAPs and GHGs (methane, CO 2 ) - including running equipment Contamination of sources of drinking and surface water from spills, faulty well construction etc.

41 Potential Environmental Impacts of Fracking Stress on surface/ground water supplies due to withdrawal of large volumes. Mining of sand. Air pollution from release of VOCs, NOx, HAPs and GHGs (methane, CO 2 ) - including running equipment Increased earthquakes observed in oil and gas producing areas Contamination of sources of drinking and surface water from spills, faulty well construction etc. Adverse effects from discharges into surface waters (if treatment of wastewater is inadequate) or storage pools/pits. Impacts of disposal into underground injection wells. (water contamination, etc.)

42 Who Regulates? (State vs. Federal) Answer: Both. Cooperative Federalism is a hallmark of many environmental regulations (CAA, CWA). EPA issues Regulations that sets limits for pollutants, or technology required. It s up to the states to form plans to find a way to implement policies to meet those standards» Allows States to tailor policies to their own specific circumstances, while exercising total control over the process.» ONLY when state plans fail to meet those standards, or are otherwise found inadequate, does the Federal Gov t step in and regulate directly. Exception: federal/indian lands. Fed Gov t has direct control. EPA has limited levers to introduce standards and impact drilling.

43 Levers for Federal / EPA Regulation of Fracking Authority Safe Drinking Water Act SDWA (Underground Injection Control) Clean Water Act CWA (Effluent Guidelines Program) / National Pollutant Discharge Elimination System (NPDES) CWA/NPDES Resource Conservation and Recovery Act (RCRA) Clean Air Act Action Regulate Fracking (If Diesel Fuels Used) To protect drinking water, set requirements for siting, construction and operation of wells. Status: Was expected to be finalized by end 212; Sent to OMB Sep 213. Underground Injection of Waste Disposal Fluids Status: Already Regulated, Class II wells. Treatment of Wastewater Discharges On-site, direct discharge is prohibited; concern is that public/private treatment facilities are not equipped to handle fracking wastewater. Status: No national standards for treatment. Update: Nat Gas proposal expected in Oct. 214, Final 215. Stormwater Discharges from Oil/Gas Operations Status: No permits required unless reportable spill/water quality violation Use of Surface Impoundments for Storage or Disposal of Fracking Fluids Status: EPA evaluating and considering need for technical guidance for pits, storage tanks, etc. RCRA exemptions exist for E&P waste. Air Regulations for the Oil and Natural Gas Industry (NSPS/NESHAP) Green Completions required for newly-fractured gas (but not oil) wells. Flaring OK until 215. Requirements for other equipment. Status: Final Rule released April 17 th, 212 some issues granted reconsideration.

44 Federal Gov t Actions in Past 12 months Not much. Actually has backed off quite a bit.» NSPS/NESHAP for VOCs published in August 212. Since then, reconsideration granted on many issues in line with industry concerns. Definitive EPA study on Groundwater contamination delayed» Final report was expected end-214, now 216 Ensures any fallout from results will be the next President s problem. Issue for Industry? Enviro Groups have been pointing to on-going study in courts and elsewhere as proof that closer scrutiny of the practice is warranted. Pavillion, WY; Parker County, TX; Dimock, PA Investigations» In all 3 instances EPA had initially found evidence of water contaminated by fracking activities but have either dropped the case or turned them over to the states and industry for further investigation. Reason to believe investigations on federal level will be slow to develop.

45 Impact of Restrictions on Federal Lands Limited Bakken Marcellus Uinta-Piceance Niobrara Utica Mississippi Lime Monterey Granite Wash Permian Basin Shales Eagle Ford Woodford Barnett Haynesville Fayetteville Lower Smackover Tuscaloosa Marine

46 Forecasted Shale Crude Production in U.S. to 23 (in MBD) The Rest Texas North Dakota

47 Methane a Key Issue According to IPCCC, methane is 72-25x worse for global warming than CO 2 over 2, 1 years, respectively. Concept introduced to public by controversial Cornell Study in 211 with methane emissions GHG impact worse than coal» Since then a number of studies have been released giving various views on the amount of methane released during fracking.» UT/EDF/Industry study (9/17) said majority of well completions have equipment to cut methane by 99%. However, leaks from pneumatic devises 3%+ higher than current EPA estimates. Right now, no direct controls NSPS for VOCs has co-benefit of significantly reducing methane.» New regs coming for fracked oil wells, pneumatic valves, increased oversight?

48 Sharp Jump in Production Leaves Increasing Amounts of Stranded Gas / Flaring: North Dakota BCF/month Difference BCF Produced BCF Sold Source: NDIC Oil and Gas Division

49 Bakken North Dakota HB 1134 Addresses Efforts to Reduce Flaring enacted in April 213.» After 1 year grace period, well operators must either: 1) cap the well; 2) connect the well to a gas gathering line; or 3) Equip the site with an electric generator using >75% of the base from the well. Exception: Requirements eliminated in case of economic infeasibility. Swallow the rule? Tax incentives: exemption from state s 6.5% production tax if at least 75% of gas captured.» By either: 1) using the gas in on-site generators; or 2) bringing it to market via pipeline.» Producers drilling many wells on same site might make pipelines more feasible. Regs currently proposed will implement the law AND:» Toughens requirements for economic infeasibility exception.» Finalized by end-213; will be effective starting April 214.

50 Texas TRRC Adopted Amendments to Well Construction Requirements (Statewide Rule 13)» First major upgrade of well integrity rules in 3 years.» Rules include: Required testing of well casings to Max Pressure expected during fracking and notify RRC of a failed test Required cement across and above all zones permitted for injections or disposal wells New/clarified requirements for wells with completions that include fracking treatments New requirements for well control and blowout preventers Clarified standards for drilling, casing, and cementing of wells.» Rules received praise from both industry and Enviro groups.» Will go into effect Jan 1, 214.

51 California Comprehensive bill SB 4 signed into Law» New Permitting Rules (previously special permits were not required)» Chemical-disclosure requirements CBI must be disclosed to Gov t and health professionals strictest in nation.» Expanded oversight of Wastewater disposal.» Applies to acidization and other well-stimulation techniques beyond fracking.» But NO MORATORIUM. (Several such bills were killed this year). Directs DOGGR to draft rules and permit system by 215 Controversy?» Late amendment pushed by Gov. Brown has exceptions for permitting. How will the law be interpreted?» Amendments expected.

52 Public Opinion: Increased Opposition for Fracking in last 18 Months? 6 % of Respondents who Oppose Use of Hydraulic Fracturing Pew UT Austin 1 % Mar-12 Sep-12 Mar-13 Sep-13

53 Conclusions Federal Level:» No Meaningful action. BLM rules unlikely to have impact. Enforcement relaxed. Important studies abandoned and/or delayed. State Level:» Continue to develop meaningful regulation to address issues, but no major threat to production. Public Opinion:» Is recent trend meaningful? What is driving it? Wildcards:» Smoking gun incident/study?» Seismic Activity?» Droughts?

54 PIRA Energy Group U.S. Shale Liquids Production: What Have Another 12 Months Taught Us? Bill Fuller Senior Director, International Oil Annual Retainer Client Seminar New York City: October 1-11, 213

55 U.S. Shale Resource Base U.S. Non-Shale Developments Canada Developments

56 Major U.S. Developments Over Past Year U.S. Shale / Tight Sands assessed resource base increased Non-Shale onshore crude production continues about stable Resurgence in Gulf of Mexico announced projects Alaska offshore exploration setback NGL production growth remains strong Biofuels growth stronger in 214 after drought hurt 12 & 13 New Lower 48 Gas-to-Liquids looks firmer

57 Bakken: Deeper Three Forks Layers ( Benches ) Have Added to Resource (Estimated Ultimate Recovery) Layers Depth, Feet Continental Resources Assessments Middle Bakken & Three Forks 1 Formations 5,7 8, Impact of including Lower Three Forks 1, PIRA Assessment 27 Bn Bbls oil recoverable (unrisked); risking lowers to 19 Bn Bbls

58 Bakken Shale Recoverable Resource Estimated at 22 Bn Bbls Oil Equivalent Bakken Shale Additional layers resulted in increase in PIRA s Bakken area crude oil un-risked EUR from 18 Bn Bbls Sep 12 to 27 Bn Bbls currently. But, risking lowers current assessment to 19 Bn Bbls crude oil. Newer lower layers discounted heavily due less drilling data.

59 Pioneer Has Increased Assessment for Permian Basin s Spraberry / Wolfcamp to be Largest field in U.S. Deeper drilling Into Wolfcamp Shale has resulted in Larger Permian Basin resource Pioneer, April 213 Spraberry / Wolfcamp 43 BBOE if ex Jo Mill assessment. PIRA Assessment, Sep 213 Wolfcamp EUR 44 Bboe, inc Cline, ex Jo Mill (Jo Mill not assessed yet). PIRA Total Permian Basin EUR 55 Bboe (Crude 37 Bboe).

60 U.S. Shale / Tight Oil Resource Base, Risked - Estimated Ultimately Recoverable Reserves (EUR) Bn Bbls, Crude & Condensate Total U.S. Crude & Condensate Risked EUR 133 Bn Bbls Total Oct 13 Risked EUR Un-Risked EUR 175 Bn Bbls Total Sep 12 was 113 Bn Bbls, Un-Risked). Risked Sep 13 revised up 2 Bn Bbls vs Un-Risked Sep 12.

61 Shale Crude and NGL Drives Total U.S. Supply Up in Near Term 14 MMB/D Production 1.4 MMB/D Growth Shale Crude Shale NGL Non-Shale Crude On. Non-Shale Crude Off. Non-Shale NGL Biofuels Other Liquids Refinery Gain

62 Shale Crude Makes Texas Production Skyrocket and Moves North Dakota into Second Highest in U.S. 3. MMB/D Top 5 Crude Producing States in U.S. TX ND Alaska California North Dakota Oklahoma Texas

63 U.S. Permian Basin Rejuvenation Continues Non-Shale Crude Largest Component; Growth Mainly Shale MB/D MB/D Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

64 New Infrastructure Allows Continued Growth in Total Permian Basin Output Production Largest Component: Non-Shale Crude Largest Growth: Shale Crude 25 2 MB/D Growth Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec -5 Jan-9 Jan-1 Jan-11 Jan-12 Jan-13 Jan Year-on-Year Growth

65 Lower 48 Onshore Crude Production Ex Shale Crude Grows Slightly due to Permian Basin MMB/D U.S. crude on long term decline since peaking /99 oil price collapse (Asian Financial Crisis) sharpens decline 29 price collapse (Global Recession) cuts drilling Resurgence of Permian Basin non-shale crude L48 Onshore Crude ex Shale Crude Last Year s Outlook Non-shale L48 onshore crude production grew faster than expected last year Lower48 Onshore ex Shale Sep'12 Forecast

66 Gulf of Mexico Has Begun Recovery from Aftermath of Macondo Well Disaster 6 5 GOM Approved Drilling Permits 3-Month Rolling Average GOM Production & Rig Count Highest Rig Count Since Moratorium Jun-1 Oct-1 Feb-11 Jun-11 Oct-11 Feb-12 Jun-12 Oct-12 Feb-13 Jun-13 Shallow Deep Jan-9 Jul-9 Jan-1 Jul-1 Jan-11 Jul-11 Jan-12 Jul-12 Jan-13 Jul-13 Jan-14 Jul-14 Production Rig Count

67 U.S. NGL Growth Dominated by Shale NGL Production Growth MMB/D Total NGL surprises to upside vs last year s outlook.4.3 MMB/D Shale NGL Non-Shale NGL Shale NGL Non-Shale NGL

68 Impact of Price Rise Starting 1 Years Ago Has Resulted in Halt to Four Decades of U.S. Crude Decline MMB/D Higher prices starting 23 versus $2-$3/Bbl since 198 s have had delayed elasticity of supply impact; Not just shale crude, but all crude Other L48 Onshore Calif. Offshore Federal GOM Alaska On+Off Shore L48 Shale Crude

69 U.S. Total Oil Supply Growth Remains Strong in Medium Term then Tapers off Long Term MMB/D Production Shale Crude Shale NGL Non-Shale Crude On. Non-Shale Crude Off. Non-Shale NGL Biofuels Other Liquids Refinery Gain MMB/D Growth

70 U.S. Crude Oil Production Quality Becomes Lighter and Sweeter As Shale Crude Grows MMB/D Lt Sweet Lt Sour Med Sweet Med Sour Hvy Sweet Hvy Sour

71 North America Supply Covers Largest Share of World s Demand Growth MMB/D Growth North America Supply as % of World Demand % 249% 94% 7% World Demand Growth U.S. Supply Canada Supply All Other Supply No. Amer. Supply World Demand

72 Major Canada Developments Over Past Year First Standalone Bitumen Mine (Kearl) Started Deliveries June Planning 11 MB/D by year-end 213; Planned capacity 345 MB/D Continued Strong In Situ Bitumen Growth Expected Pipelines & Rail support growth; Growth also aided by BP Whiting Refinery as it swings to heavy crude slate early 214 Upgraders: Suncor s Voyager Project Shelved Indefinitely Past views of strong growth for synthetic crude undermined by shale crude (also light / low sulfur) & high cost of integrated upgrading. North West Redwater began construction; 1 st of three 5 MB/D phases. Shale Crude Growth Remains Slow Relative to U.S. Offshore Atlantic: ExxonMobil approved Hebron development Hebron in Jeanne d'arc basin is on track for 216 start Statoil discovered more oil in deepwater Flemish Pass Basin

73 Canada Shale/Tight Crude Production MB/D Last Actual: Mar 13 Production Last Year s Forecast Bakken Viking Cardium Montney Duvernay Other Producing New Probable New Possible MB/D 211 Bakken Cardium Duvernay New Probable Growth Viking Montney Other Producing New Possible

74 Canadian Total Crude Growth is Mainly Oil Sands and Remains Strong Both Medium Term and Long Term 7 MMB/D Production 25 MB/D Growth / Year Light Includes Shale Crude '95-' '-'5 '5-'1 '1-'15 '15-'2 '2-'25 '25-'3 Heavy Atlantic Bitumen Light/Medium Synthetic Condensate Heavy Atlantic Bitumen Light/Medium Synthetic Condensate

75 Summary of Key North American Oil Supply Drivers U.S. shale liquids growth spectacular and is transforming workings of oil markets Especially near and medium term U.S. Non-shale crude no longer declines Canadian Oil Sands provides consistent strong growth New project focus is raw bitumen because of competition from shale crude; modest shale growth Impact of North American supply growth on world markets diminishes in long term Shale liquids growths in U.S. and Canada lessen while shale growth elsewhere begins to become significant