Drilling Deeper; A Reality Check on U.S. Government Forecasts for a Lasting Tight Oil & Shale Gas Boom
J. David Hughes, October 2014 (Post Carbon Institute)
Drilling Deeper reviews the twelve shale plays that account for 82% of the tight oil production and 88% of the
shale gas production in the U.S. Department of Energy’s Energy Information Administration (EIA) reference
case forecasts through 2040. It utilizes all available production data for the plays analyzed, and assesses
historical production, well- and field-decline rates, available drilling locations, and well-quality trends for each
play, as well as counties within plays. Projections of future production rates are then made based on forecast
drilling rates (and, by implication, capital expenditures). Tight oil (shale oil) and shale gas production is found
to be unsustainable in the medium- and longer-term at the rates forecast by the EIA, which are extremely
This report finds that tight oil production from major plays will peak before 2020. Barring major new
discoveries on the scale of the Bakken or Eagle Ford, production will be far below the EIA’s forecast by 2040.
Tight oil production from the two top plays, the Bakken and Eagle Ford, will underperform the EIA’s reference
case oil recovery by 28% from 2013 to 2040, and more of this production will be front-loaded than the EIA
estimates. By 2040, production rates from the Bakken and Eagle Ford will be less than a tenth of that
projected by the EIA. Tight oil production forecast by the EIA from plays other than the Bakken and Eagle Ford
is in most cases highly optimistic and unlikely to be realized at the medium- and long-term rates projected.
Shale gas production from the top seven plays will also likely peak before 2020. Barring major new
discoveries on the scale of the Marcellus, production will be far below the EIA’s forecast by 2040. Shale gas
production from the top seven plays will underperform the EIA’s reference case forecast by 39% from 2014
to 2040, and more of this production will be front-loaded than the EIA estimates. By 2040, production rates
from these plays will be about one-third that of the EIA forecast. Production from shale gas plays other than
the top seven will need to be four times that estimated by the EIA in order to meet its reference case
Over the short term, U.S. production of both shale gas and tight oil is projected to be robust—but a thorough
review of production data from the major plays indicates that this will not be sustainable in the long term.
These findings have clear implications for medium and long term supply, and hence current domestic and
foreign policy discussions, which generally assume decades of U.S. oil and gas abundance.
Executive Summary – Key Findings
The seven tight oil plays and seven shale gas plays analyzed in this report account for 82% of projected tight
oil production and 88% of projected shale gas production through 2040 in the EIA’s Annual Energy Outlook
2014 reference case forecast. A detailed analysis of well production data from these plays resulted in these
1) Tight oil production from major plays will peak before 2020. Barring major new discoveries on the
scale of the Bakken or Eagle Ford, production will be far below EIA’s forecast by 2040.
a) Tight oil production from the two top plays, the Bakken and Eagle Ford, will underperform EIA’s
reference case oil recovery by 28% from 2013 to 2040, and more of this production will be front-loaded than the EIA estimates.
b) By 2040, production rates from the Bakken and Eagle Ford will be less than a tenth of that
projected by EIA.
c) Tight oil production forecast by the EIA from plays other than the Bakken and Eagle Ford is in
most cases highly optimistic and unlikely to be realized at the rates projected.
2) Shale gas production from the top seven plays will likely peak before 2020. Barring major new
discoveries on the scale of the Marcellus, production will be far below EIA’s forecast by 2040.
a) Shale gas production from the top seven plays will underperform EIA’s reference case forecast
by 39% from 2014 to 2040 period, and more of this production will be front-loaded than EIA
b) By 2040, production rates from these plays will be about one-third that of the EIA forecast.
c) Production from shale gas plays other than the top seven will need to be four times that
estimated by EIA in order to meet its reference case forecast.
3) Over the short term, U.S. production of both shale gas and tight oil is projected to be robust—but a
thorough review of the production data indicate that this will be unsustainable in the longer term.
These findings have clear implications for current domestic and foreign policy discussions, which
generally assume decades of U.S. oil and gas abundance.
Other factors that could limit production are public pushback as a result of health and environmental
concerns, and capital constraints that could result from lower oil or gas prices or higher interest rates. As
such factors have not been included in this analysis, the findings of this report represent a “best case”
scenario for market, capital, and political conditions.
The analysis shows that U.S. tight oil production cannot be maintained at the levels assumed by the EIA
beyond 2020. The top two plays—Bakken and Eagle Ford—which account for more than 60% of current
production, are likely to peak by 2017 and the remaining plays will make up considerably less of future
production than has been forecast by the EIA. Rather than a peak in 2021 followed by a gradual decline to
slightly below today’s levels by 2040, total U.S. tight oil production is likely to peak before 2020 and decline
to a small fraction of today’s production levels by 2040.
• The 3-year average well decline rates in the seven plays analyzed for this report (which collectively
provide 89% of current U.S. tight oil production) range from 60% to 91%.
• The high decline rates of tight oil wells in these plays means that 43% to 64% of their estimated
ultimate recovery (EUR) is recovered in the first three years.
• Field declines from the Bakken and Eagle Ford are 45% and 38% per year, respectively (this
compares to 5% per year for large conventional fields). This is the amount of production that must be
replaced each year with more drilling in order to maintain production at current levels (field decline is
made up of all wells in a play—old and new—and hence is lower than first-year well declines).
• Based on production history, drilling locations, and declining well quality, this report found that 98%
of the EIA’s projected production from these seven plays has a “high” or “very high” optimism bias.
• The EIA assumes that the equivalent of 100% of proved reserves and between 65% and 85% of its
“unproved technically recoverable tight oil resources” will be recovered by 2040 for the plays
analyzed. Considering that unproved, technically recoverable resources have no price constraints
and only loose geological constraints, this is highly speculative.
• The EIA assumes that the U.S. will exit 2040 with tight oil production at levels only marginally less
than today, at 3.2 MMbbl/d. A thorough analysis of the well production data suggests this is highly
Forecasts for Bakken & Eagle Ford Tight Oil Plays
• The EIA’s forecast of the timing of peak production in the Bakken and Eagle Ford is similar to this
report, as is the rate of peak production.
• The EIA forecasts a much higher tail after peak production, with recovery of 19.2 billion barrels
between 2012 and 2040, as opposed to 13.9 billion barrels forecast in this report.
• The EIA forecasts collective production from the Bakken and Eagle Ford to be a little over 1 million
barrels per day in 2040. In contrast, the “Most Likely” drilling rate scenario presented in this report
forecasts that production will fall to about 73,000 barrels per day by 2040.
Forecasts of Other Tight Oil Plays
• To meet the EIA’s forecasts, all other plays together would need to produce over twice as much
through 2040 as what is projected for the Bakken and Eagle Ford.
• The major remaining tight oil plays are the three Permian Basin plays—Spraberry, Wolfcamp, and
Avalon/Bone Spring—plus the Austin Chalk and the Niobrara. EIA forecasts expect these plays to
produce four to five times their historical production in the next 26 years, but this is highly
questionable, considering that:
- These plays are already 40-60 years old, with tens of thousands of wells already drilled.
- The Permian Basin plays’ average initial well productivities are half or less the average of core
counties in the Bakken or Eagle Ford.
- The Bakken and Eagle Ford’s average estimated ultimate recovery (EUR) per well is two to more
than six times higher than that of these other plays.
The EIA now projects domestic gas production to reach nearly 38 trillion cubic feet per year by 2040, which is
55% above 2013 levels. The bulk of this production growth would come from shale gas.
This analysis shows that simply maintaining U.S. shale gas production in the medium term—let alone
increasing production at rates forecast by the EIA through 2040—will be problematic. Four of the top seven
shale gas plays are already in decline. Of the major plays, only the Marcellus, Eagle Ford, and Bakken (the
latter two are tight oil plays producing associated gas) are growing; and yet, the EIA reference case gas
forecast calls for plays currently in decline to grow to new production highs, at moderate future prices.
Although significantly higher gas prices needed to justify higher drilling rates could temporarily reverse
decline in some of these plays, the EIA forecast is unlikely to be realized.
• The 3-year average well decline rates in the seven plays analyzed for this report (which collectively
provide 88% of U.S. shale gas production) ranges between 74% and 82%.
• The average field decline rates for these plays ranges between 23% and 49%, meaning that between
one-quarter and one-half of all production in each play must be replaced each year in order to simply
maintain current production.
• Although the EIA forecast for the Marcellus play is rated as “reasonable” and its forecast for the
Bakken play is rated “conservative,” the deficit left by being “very highly optimistic” on some of the
other plays makes finding and developing the gas required to meet the overall forecast unlikely.
• Because productivity of shale wells declines rapidly, many new wells must be drilled just to maintain
existing production levels. Of the top shale gas plays, only the Marcellus, Eagle Ford, and Bakken are
currently seeing enough drilling to maintain and grow production.
• Major shale gas plays are variable in well quality. The Marcellus and Haynesville are much more
productive on average than the other plays analyzed in this report. Even within plays, well quality
• Despite years of concerted efforts and claims that technological innovation can overcome steep well
decline rates and the move from “sweet spots” to lower quality parts of plays, average well
productivity has gone flat in all major shale gas plays except the Marcellus.
• Approximately 130,000 additional shale gas wells will need to be drilled by 2040 to meet the
projections of this report, on top of the 50,000 wells drilled in these plays through 2013. Assuming
an average well cost of $7 million, this would require $910 billion of additional capital input by 2040,
not including leasing, operating, and other ancillary costs.
Forecasts for Shale Gas Plays
• The EIA assumes that 74% to 110% of its “unproved technically recoverable resources” plus “proved
reserves” will be recovered by 2040 for the seven major plays analyzed. Considering that unproved,
technically recoverable resources have no price constraints and only loose geological constraints,
this is highly speculative.
• This analysis found that the EIA reference case forecast for the top seven shale gas plays
overestimates cumulative production through 2040 in this report’s “Most Likely” scenario by 64%.
• The EIA further estimates that in 2040, shale gas production from the seven plays analyzed will be
182% higher (nearly 3 times) than estimated in this report—and that by 2040, another 49.6 Tcf will
have been recovered from other plays not analyzed in this report.
• In this report’s “Most Likely” scenario, cumulative dry shale gas production over the 2014-2040
period is 229.5 trillion cubic feet (Tcf)—46% lower than the EIA Reference Case (377 Tcf).
• In this report’s “Most Likely” scenario, shale gas production from the seven plays analyzed peaks in
the 2016-2017 timeframe and declines by more than half, to 14.8 billion cubic feet per day (Bcf/d)
by 2040. In contrast, the EIA expects production from these plays to keep growing through 2040,
with shale gas production in that year at 41.8 Bcf/d—nearly three times higher than this report finds
This report shows that the EIA’s optimistic forecasts for future U.S. tight oil and shale gas production are
based on a set of false premises, namely that:
• High-quality shale plays are ubiquitous, and there will be always be new discoveries and production
from emerging plays to fill the gap left by declining production from major existing plays.
• Technological advances can overcome steep decline rates and declining well quality as drilling
moves from sweet spots to poorer quality rock, in order to maintain high production rates.
• Large estimated resources underground imply high and durable rates of extraction over decades.
Actual production data from the past decade of shale gas and tight oil drilling clearly do not support these
assumptions. Unfortunately, the EIA’s rosy forecasts have led policymakers and the American public to
believe a number of false promises:
• That cheap and abundant natural gas supplies can create a domestic manufacturing resurgence and
millions of new jobs over the long term.15
• That abundant domestic oil and natural gas resources justify lifting the oil export ban (imposed 40
years ago after the Arab oil embargo)
16 and fast-tracking approval of liquefied natural gas (LNG)
• That the U.S. can use its newfound energy strength to shift geopolitical trends in our long-term
• That we can easily limit carbon dioxide emissions from power plants as a result of natural gas
replacing coal as the primary source of electricity production. The promises associated with the expectation of robust and relatively cheap shale gas and high-cost but
rising tight oil production have also led to a tempering of investments in renewable energy and nuclear
power. If, as this report shows, these premises and promises are indeed false, the implications are
profound. It calls into question plans for LNG and crude oil exports and the benefits of the shale boom in light
of the amount of drilling and capital investment that would be required, along with the environmental and
health impacts associated with it. Conventional wisdom holds that the shale boom will last for decades,
leaving the U.S. woefully unprepared for a painful, costly, and unexpected shock when the shale boom winds
down sooner than expected. Rather than planning for a future where domestic oil and natural gas production
is maintained at current or higher levels, we would be wise to harness this temporary fossil fuel bounty to
quickly develop a truly sustainable energy policy—one that is based on conservation, efficiency, and a rapid
transition to distributed renewable energy production.