Tight Oil Money Return on Investment Eagle Ford Shale Case History - - PowerPoint PPT Presentation

Slide 1 Labyrinth Consulting Services, Inc. artberman.com

Tight Oil Money Return on Investment Eagle Ford Shale Case History

Art Berman Labyrinth Consulting Services, Inc. American Chemical Society New Orleans, LA March 21, 2018

Slide 2 Labyrinth Consulting Services, Inc. artberman.com

The Eagle Ford Shale Play

• Located in South Texas between San Antonio and Corpus Christi.
• Horizontal drilling and hydraulic fracturing began in 2008.
• Approximately 17,000 producing wells.
• February production was 935,000 bo/d, down from 1,324,000 in December 2014.
• 71 active horizontal rigs.
• An over-saturated solution gas drive mechanism with a minor structural component.
• Production is volatile oil and condensate.
• 88% of the oil is > 40 API gravity and 32% is > 50 API gravity.

Corpus Christi Houston San Antonio

EAGLE FORD SHALE PLAY

3.2 3.4 3.6 3.8 4.0 4.2 4.4 4.6 4.8 5.0 Jan-15 Mar-15 May-15 Jul-15 Sep-15 Nov-15 Jan-16 Mar-16 May-16 Jul-16 Sep-16 Nov-16 Jan-17 Mar-17 May-17 Jul-17 Sep-17 Nov-17 Jan-18 Incremental Production Since April 2015 (mmb/d)

U.S. Oil Future is a Bet On a Single Play Permian Basin is the Only Tight Oil Play Producing More Oil Than the April 2015 Peak Following the OIl-Price Collapse

Source: EIA & Labyrinth Consulting Services, Inc.

Eagle Ford Bakken Anadarko Niobrara Permian Eagle Ford Bakken Base

2015 Previous Peak Production

Anadarko Niobrara

Slide 3 Labyrinth Consulting Services, Inc. artberman.com

Eagle Ford Well Performance Evaluation by Decline-Curve Analysis

100 1,000 10,000 100,000 1 10 100 Rate, bbls or Mscf/month Time months

Log Log Plot Rate vs Time Points = Actual Data Line = Forecast Oil = Green, Gas = Red

100 1,000 10,000 100,000 5 10 15 20 25 30 35 40 45 50 55 60 Monthly Rate, bbls or Mscf Months from First Production

Semi-Log Plot of Rate vs. Time Points = Actual Data Line = Forecast Oil = Green, Gas = Red

EOG 2013 OIL GAS Max 57,000 53,000 b 1.25 1.30 Di 20.00 12.00 EUR 401,691 295,699 100 1,000 10,000 100,000 1 10 100 Rate, bbls or Mscf/month Time months

Log Log Plot Rate vs Time Points = Actual Data Line = Forecast Oil = Green, Gas = Red

100 1,000 10,000 100,000 5 10 15 20 25 30 35 40 45 50 55 60 Monthly Rate, bbls or Mscf Months from First Production

Semi-Log Plot of Rate vs. Time Points = Actual Data Line = Forecast Oil = Green, Gas = Red

DVN 2014 OIL GAS Max 30,000 70,000 b 0.475 0.45 Di 1.80 1.20 EUR 370,863 1,100,892

• Top 6 Eagle Ford operators were evaluated: Chesapeake, ConocoPhillips, Devon, EOG, Marathon, &

Sanchez.

• Standard rate vs time decline-curve analysis was used to match production and determine EUR

(estimated ultimate recovery).

• Production was normalized and vintaged by year of first production.
• Group decline-curve analysis by operator & vintaged year of first production from 2013-2016.
• Matches were good to excellent for most operators and vintage-year groups.
• 2017 was problematic as expected because of short production history.
• Standard semi-log plots were used in conjunction with log-log plots to calibrate b-exponents for

hyperbolic decline.

• Oil and gas streams were declined separately and later integrated through BOE (barrel of oil

equivalent) conversion.

Slide 4 Labyrinth Consulting Services, Inc. artberman.com

Integrating Oil, Natural Gas & Natural Gas Liquids (NGL) Production

• The standard conversion of natural gas-to-barrels of oil equivalent is 6:1 based on energy content.
• A value relationship of oil & gas is more useful for economic analysis:

Ø $60 (oil spot)/$2.75 (gas spot) = 22.

• NGL (natural gas liquids) production is not reported to the Texas Railroad Commission but annual

data is available in 10-K annual filings for companies that are pure Eagle Ford players.

• An average value of 80 barrels per million cubic feet of gas was used:

Ø 80 BPM at 42% of oil value. Ø 0.08 x (0.42*$60) = $2.02 uplift/mcf gas.

• Gas shrinkage of 86%: $2.75 * 0.86 = $2.37/mcf.
• NGL + Gas: $2.02 + $2.37 = $4.38/mcf.
• BOE conversion: $60/$4.38 = 14 mcf/BOE.
• Eagle Ford wellhead price is ~$2.20 less than WTI.
• Sanchez’s—the only pure Eagle Ford player evaluated—2017 realized price was $48.60 & 2017

average WTI spot price was $50.88.

Slide 5 Labyrinth Consulting Services, Inc. artberman.com

Applying EUR to All Wells

• EUR from decline-curve analysis was correlated with 12-month cumulative production.
• The resulting conversion of 2.36 * 12-month cumulative was applied to all wells with at least 12

months of production.

• The resulting EUR map revealed 2 core areas in the northeastern and southwestern parts of the play.
• Contours were color-coded to 25% IRR at $55 wellhead prices (375,000 boe EUR).
• Number of acres and producing wells inside 375 kboe contours were determined.
• The northeastern core area is mostly volatile oil and is developed on ~110 acre/well density.
• The southwestern area is mostly condensate and is developed on ~175 acre/well density.

Slide 6 Labyrinth Consulting Services, Inc. artberman.com

Eagle Ford Variable Operating Expenses

• Production expenses—lifting costs—are ~$9/boe.
• Variable operating expenses were ~$14.75 per barrel of oil equivalent in 2017 based on EOG &

Sanchez.

• Our long-term standard “plug” number has been $12/BOE but the shift to development &

maintenance mode in the Eagle Ford has increased costs.

• $13 variable OPEX used for economics (optimistic).
• Interest expense because of high debt load was a significant cost for most companies.
• $5.5 mm drilling and completion costs.

Slide 7 Labyrinth Consulting Services, Inc. artberman.com

Eagle Ford EUR and Economic Results

• 2014 was the best year for Eagle Ford EUR: weighted average of top companies was 300 kboe.
• 2013 and 2015 were the worst years evaluated.
• 2016 was slightly better than 2015.
• 2017 EUR includes considerable uncertainty because of short production history but the weighted

average was slightly lower than 2016.

• The weighted average EUR for all companies-all years is ~300 kboe with an associated $50.66/barrel

wellhead or about $53 WTI price.

• At $55 wellhead price (~$57.50 WTI) most companies had positive NVP 8 and IRR > 10%.
• The Eagle Ford play is marginally profitable overall at projected 2018 WTI prices in the mid-$50

range.

• EOG, Devon and ConocoPhillips have attractive NPV and IRR at those prices.
• Using $50 as a baseline, approximately 1.1 billion barrels of oil were produced at a loss in 2015 &

2016—about 45% of cumulative Eagle Ford production since 2008 of 2.4 billion barrels equivalent.

Slide 8 Labyrinth Consulting Services, Inc. artberman.com

$0 $10 $20 $30 $40 $50 $60 $70 $80 $90 $100 $110 $120 $130 $140 0.0 50.0 100.0 150.0 200.0 250.0 300.0 350.0 400.0 450.0 500.0 Dec-85 Oct-86 Aug-87 Jun-88 Apr-89 Feb-90 Dec-90 Oct-91 Aug-92 Jun-93 Apr-94 Feb-95 Dec-95 Oct-96 Aug-97 Jun-98 Apr-99 Feb-00 Dec-00 Oct-01 Aug-02 Jun-03 Apr-04 Feb-05 Dec-05 Oct-06 Aug-07 Jun-08 Apr-09 Feb-10 Dec-10 Oct-11 Aug-12 Jun-13 Apr-14 Feb-15 Dec-15 Oct-16 Aug-17 WTI Price ($/barrel) Oil & Gas Well Drilling Producer Price Index (1985 = 100)

4-Fold Increase In O&G Well Drilling Producer Price Index From 2004-2014 WTI Oil Price (RHS) Oil & Gas Well Drilling Cost Index (LHS)

Source: U.S. Federal Reserve Bank, EIA & Labyrinth Consulting Services, Inc.

4-Fold Increase in O&G PPI Becauseof Unconventional Oil & Gas 2004-2014 Because of Higher Cost of Unconventional Technology 40% Decrease After Oil Price Collapse but 7% Increase in 2017 +7%

~40% Decrease From Deflation

Economics Are Optimistic For 2013 & 2014 Eagle Ford

• Drilling and completion costs before about mid-2015 were considerably higher: $7-9 mm per well.
• Economics are optimistic for these wells because $5.5 mm was used in all economics.
• Popular perception is that lower well costs are primarily because of improved technology and
• perator efficiency.
• In fact, about 90% of cost savings are because of price deflation after the oil-price collapse in 2014.
• Most well performance improvements are because of better completion methods.
• Data suggests, however, that much of this is rate acceleration and not reserve addition.

Slide 9 Labyrinth Consulting Services, Inc. artberman.com

8.3 5.3 2.0 1.8 1.6 1.5 1.5 1.5 1.4 1.4 1.3 1.2 1.1 1.1 1.1 1.1 1.0 0.9 0.9 0.7 0.7 0.6 1 2 3 4 5 6 7 8 9 Parsley Oasis Hess Sanchez Callon Energen Concho Whiting Laredo Newfield Statoil Marathon Apache Pioneer EOG Diamondback Devon Continental Murphy OXY EPE ConocoPhillips Ratio of Capital Expenditures to Cash From Operations

Tight Oil Is a Marginal Business At Best 73% of Companies Lose Money (Capex > Cash From Operations) Based on 10-K Filings for Full Year 2017

Make Money

Cash Flow > Capex

Lose Money

Capex > Cash Flow

Source: Yahoo Finance & Labyrinth Consulting Services, Inc.

Break Even

*Chesapeake has not filed a 2017 10-K but Capex-Cash Flow cannot be calculated because cash from operations was negative through Q3 2017

10.1 9.4 6.8 6.1 4.8 4.8 4.6 3.5 3.3 3.3 3.1 3.1 3.0 2.6 2.6 2.4 2.1 1.9 1.8 1.7 1.6 1.1 2 4 6 8 10 12 Oasis Sanchez Hess Marathon EPE Whiting Parsley Devon Callon Apache Statoil Continental EOG Murphy Newfield ConocoPhillips Laredo OXY Energen Diamondback Concho Pioneer Ratio of Capital Expenditures to Cash From Operations

Tight Oil Is a Marginal Business At Best: Debt/Cash flow Only 23% of Key Operators Have Acceptable Debt-to-Cash Flow Ratios (< 2) 45% are Risky (2-4) & 32% are Unacceptable (> 4) Based on 10-K Filings for Full Year 2017

Source: Yahoo Finance & Labyrinth Consulting Services, Inc.

Acceptable < 2 Risky 2 -4 Unacceptable > 4

*Chesapeake has not filed a 2017 10-K but Debt-Cash Flow cannot be calculated because cash from operations was negative through Q3 2017

Where Are the Profits?

• Most tight oil companies lost money in 2017 based on full-year 10-K filings.
• Capital expenditures were greater than cash from operations for 73% of evaluated companies.
• Risky to unacceptably high debt levels characterize 77% of tight oil companies.
• Companies have been claiming profitability at prices below 2017 average levels ($51 WTI) since

2016.

• This study suggests that was not generally true in the Eagle Ford Shale play.
• Corporate financial filings confirm the economics from this study.
• Tight oil remains a marginal business after 10 years of production.

Slide 10 Labyrinth Consulting Services, Inc. artberman.com

5,000 10,000 15,000 20,000 25,000 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 Monthly Oil Production (barrels) Months of Production

Conoco Phillips 2017 Wells Eagle Ford Wells Have Steeper Decline Rate Than Wells From Previous Years Despite Higher Initial Production Levels

2013 2015 2014

2017

Source: Drilling Info & Labyrinth Consulting Services, Inc.

1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 9,000 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 Monthly Oil Production (barrels) Months of Production

Sanchez 2016 & 2017 Eagle Ford Wells Have Steeper Decline Rates Than Wells From Previous Years 2016

2013 2015 2014

2017

Source: Drilling Info & Labyrinth Consulting Services, Inc.

5,000 10,000 15,000 20,000 25,000 30,000 35,000 40,000 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 Monthlly Oil Production (barrels) Months of Production

EOG 2016 & 2017 Wells Eagle Ford Wells Have Steeper Decline Rate Than Wells From Previous Years Despite Higher Initial Production Levels

2013 2015 2014

2017

Source: Drilling Info & Labyrinth Consulting Services, Inc.

2016

Initial High Production Rates Can Be Deceptive

• Cumulative production comparisons indicate that well performance in recent years is poorer than in

previous years.

• 2017 wells for EOG and ConocoPhillips had high initial production rates but steeper decline rates

than 2016 wells.

• 2017 wells for these companies are likely to have lower EURs than 2016 wells as a result.
• EOG 2016 wells appear to be crossing 2015 trends and may have lower EURs than in that year also.
• Sanchez 2017 and 2016 wells appear to be much worse than wells in most previous years.
• These comparisons represent averages but suggest that claims of performance improvements may

be premature.

Slide 11 Labyrinth Consulting Services, Inc. artberman.com

Implications for Future Production

• EUR analysis and cumulative production comparisons suggest that much of the Eagle Ford is

probably at or beyond optimum development.

• High EURs for Eagle Ford suggest large drainage areas.
• Current well spacing of 100 acres probably exceeds optimum infill.
• Poorer late-year well performance may be due to well interference.
• Operators talk about the potential of of developing additional zones.
• This is always a possibility but it seems reasonable that these other levels are already contacted by

exiting frack vertical dimensions.

• This study confirms the attractiveness of the Eagle Ford play but suggests that its best days may be

in the past.

Slide 12 Labyrinth Consulting Services, Inc. artberman.com

• This study shows that Eagle Ford wells for top operators average 300 kboe but many operators claim

EURs that are considerably higher.

• Part of the disparity is explained by BOE conversion factors: a barrel of NGLs is counted the same as

a barrel of oil even though its energy content and value are less than half of a barrel of crude oil.

• A 6:1 natural gas to boe conversion accurately reflects energy content but not value.
• Sanchez shows how it arrives at 877 boe for an average Comanche Area well.
• Using the value-based approach, the average Sanchez Comanche well is 572 boe--a difference of

35%.

• 877 boe also represents a “3-Stream EUR” consisting of multiple zone completion in upper & lower

Eagle Ford & Austin Chalk. This is somewhat misleading and represents “possible” not proven reserves.

• It is unclear how representative “Comanche Area 3” is of Sanchez’s average wells.

Reconciling Study EUR Observations With Operator Claims

Slide 13 Labyrinth Consulting Services, Inc. artberman.com

1177 1492 200 400 600 800 1000 1200 1400 1600 1800 (100)

• 100

200 300 400 500 Jan-14 Mar-14 May-14 Jul-14 Sep-14 Nov-14 Jan-15 Mar-15 May-15 Jul-15 Sep-15 Nov-15 Jan-16 Mar-16 May-16 Jul-16 Sep-16 Nov-16 Jan-17 Mar-17 May-17 Jul-17 Sep-17 Nov-17 Jan-18 Drilled Uncompeted (DUC) Wells Wells Drilled & Completed Per Month

More Eagle Ford Wells Being Completed in 2018 vs 2017 With Higher Oil Prices & More Frack Crews 1,492 Eagle Ford DUCs (drilled uncompleted wells) 315 DUCs added since Nov 2016

DUCs (RHS) Drilled Completed

Source: EIA & Labyrinth Consulting Services, Inc. YEAR Drilled Completed DUC DUCs/Mo PCT DUC/WellsDrilled 2018 YTD 356 293 14 7 4% 2017 1,982 1,697 285 24 14%

Nov 2016 Feb 2018

$20 $25 $30 $35 $40 $45 $50 $55 $60 $65 $70 $75 $80 $85 $90 $95 $100 $105 $110 $115 $120

• 50.00

0.00 50.00 100.00 150.00 200.00 250.00

Crude + Product Comparative Inventory Decreased -4.3 mmb Week Ending Mar 9

Comparative Inventory (C.I.) Millions of Barrels WTI Price ($/barrel)

Source: EIA & Labyrinth Consulting Services, Inc.- Aperio Energy Research

Mar-June 2015 False Optimism Early 2017 OPEC Production-Cut Optimism 2012-13 Market Optimism Late 2015-Early 2016 Market Pessimism

Mid-Cycle Price ~$65 Mid-Cycle Price ~$73

Long-Term Yield Curve Emerging 2018 Yield Curve?

Comparative Inventory (C.I.) Millions of Barrels WTI Price ($/barrel)

Source: EIA & Labyrinth Consulting Services, Inc.- Aperio Energy Research

Mar-June 2015 False Optimism Early 2017 OPEC Production-Cut Optimism 2012-13 Market Optimism Late 2015-Early 2016 Market Pessimism

Mid-Cycle Price ~$65 Mid-Cycle Price ~$73

Mar 9 $61.65

Larger-than-Avg Crude Addition (+5.0 vs +3 mmb 5YA) Offset by Larger-than-Avg Gasoline (-6.3 vs -2.6 mmb 5YA) & Distillate (-4.4 vs -0.7 mmb 5YA) Withdrawals WTI Correctly Priced at Weekly Avg $61.05 Price Based on Emerging 2018 Yield Curve

Implications for Future Oil Prices

• Oil prices have been stagnant for several weeks after reaching $66 WTI in early February.
• Prices are above $65 today but oil traders are bearish about the direction of prices in 2018.
• IEA and EIA have warned about the explosion of tight oil production and U.S. supply is above 1970

record high levels.

• The rig count has doubled at mostly sub-$50 prices and the number of drilled, uncompleted wells

continues to grow.

• It is likely that the market has re-priced oil downward because there is adequate to more-than-

adequate supply for the near term.

• $65+/- may represent the high mark for the unfolding next price cycle and the possibility of

downside is at least as high as higher prices.

Slide 14 Labyrinth Consulting Services, Inc. artberman.com

Concluding Observations

• Tight oil plays have added a decade of additional supply to the U.S.
• Reserves are not large (15 billion barrels) by global standards especially considering the ~90,000

current wells needed to produce 5 mmb/d.

• Tight oil is more expensive than conventional plays because horizontal drilling and hydraulic

fracturing is costly (despite lower prices).

• The present price of WTI is 2.5 times higher than average prices 1986-2004 in constant 2017 dollars.
• Technology does not create energy. It permits extraction of known resources at higher rates.
• Tight oil economics are marginal to date although current prices should make most plays profitable.
• Over-production was the main factor in the oil-price collapse in 2014. Resurgent over-production is

likely to depress prices again.

• Tight oil volumes have surprised many analysts.
• Future supply is solely dependent on capital markets.

$0 $10 $20 $30 $40 $50 $60 $70 $80 $90 $100 $110 $120 $130 $140 $150 $160

Jan-70 Feb-71 Mar-72 Apr-73 May-74 Jun-75 Jul-76 Aug-77 Sep-78 Oct-79 Nov-80 Dec-81 Jan-83 Feb-84 Mar-85 Apr-86 May-87 Jun-88 Jul-89 Aug-90 Sep-91 Oct-92 Nov-93 Dec-94 Jan-96 Feb-97 Mar-98 Apr-99 May-00 Jun-01 Jul-02 Aug-03 Sep-04 Oct-05 Nov-06 Dec-07 Jan-09 Feb-10 Mar-11 Apr-12 May-13 Jun-14 Jul-15 Aug-16 Sep-17

CPI Adjusted WTI Prices (October 2017 Dollars Per Barrel)

1974-1985

Oil Shocks

• ->

Massive E&P Investment (North Sea, Mexico, Siberia) Over-Supply, Demand Destruction & Price Deflation Debt-Fueled Economic Expansion & Rapid Growth in China & East Asia

2004-2014

Massive E&P Investment (Shale, Deep Water, Heavy Oil) 2015-2017 Over-Supply & Price Deflation

Average 2015-2018 WTI Price 2.5 Times Higher Than Average 1986-2004 in Feb 2018 Dollars

Source: EIA,U.S. Bureau of Labor Statistics & Labyrinth Consulting Services, Inc.

$36 Avg

1st Bubble 1974-1985 2nd Bubble 2004-2013

$93 Avg $71 Avg $24 Avg $50 Avg

Depressed Prices 1986-2004 46% Lower Than 2004-2014 & 29% Less Than 1974-1985