Opinion

Tight Oil Money Return on Investment Eagle Ford Shale Case History


The Eagle Ford Shale Play - San Antonio

  • 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.

Eagle Ford Well Performance Evaluation by Decline-Curve Analysis

  • 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.

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.

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.

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.

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.

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

    operator 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.

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.

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.

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.

Reconciling Study EUR Observations With Operator Claims

  • 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.

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.

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.


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