Shale vs. Big Exploration
What sort of risks are you taking?
A Perspective from Wood Mackenzie Consulting
Strategy with substance
Introduction
The rapid growth of unconventional resources in North America, especially shale gas
and liquids, has generated both enormous enthusiasm and deep skepticism. Some have
proclaimed that shale represents extremely low risk, manufacturing style opportunities,
while others question whether it has or ever will truly yield the anticipated returns. The
collapse in regional gas prices has driven home the marginal nature of these assets with
their substantial exposure to commodity price risk. This, in turn, is forcing the debate
around how to best allocate sparse capital between conventional exploration programs
and unconventional resource projects, making the industry rethink how it characterizes
unconventionals.
With over a century of experience, our industry has widely adopted frameworks and tools for
understanding and quantifying risk and rewards for conventional exploration opportunities.
There are well defined stages of exploration, appraisal, development, and production, each with
their own associated risks and activities. However, the industry has yet to clearly characterize
unconventionals, and it lacks commonplace techniques for evaluating unconventional
investment opportunities against conventional options within the overall upstream portfolio
concept. This Wood Mackenzie Consulting Perspective explores these issues and examines the
risks involved with conventional vs. unconventional exploration projects.
Point-Forward Development
vs. Full Cycle Economics
No serious evaluation of conventional
exploration opportunities would
ignore inherent finding risks, and
when evaluating performance it
is only proper to look at full cycle
economics, which yield returns of
15-25%1. However, as shale plays
emerged, it became a widespread
practice to base analysis on type
curve break-evens and point-forward
rates of returns – often touted in the
range of 30-70% (and higher!). This
disconnect stemmed mostly from
analysts focused on understanding
commodity price and investment
dynamics for established plays,
combined with independent
operators wanting to emphasize the
potential profitability of their shale
drilling programs.
Using point-forward and average
well economics may be appropriate
when the distribution of well
performance is well established and
one is considering the development
potential of an already captured and
proven asset. However, this custom
of using type curves and analyzing
point-forward economics became
contributors to the perception
of shales as largely homogenous
formations with repeatable well
results offering near to zero risk.
With perceived low risk and
outstanding development economics,
competition amongst buyers drove
up the price of entry for proven
shale plays, enticing companies to
move into the next big emerging
play before access costs escalated.
However, when considering getting
into an unproven position or play,
the ‘no-risk, high return’ mentality
is dangerously flawed, though until
recently it had been masked by high
gas prices. To address this issue,
operators need to consider where
in the asset life cycle any given
unconventional opportunity sits
and build appropriate risk into the
analysis.
Comparisons Using Life Cycle
Frameworks
Conventional exploration prospects
progress through distinct life cycle
stages: Exploration, Appraisal,
Development and Production, with
clear transitions for each stage
(exploration well discovery, final
investment decision (FID), first
production and abandonment).
Following the appraisal process and
having sanctioned the project FID for
development, the industry typically
no longer applies sub-surface risk to
the entire project. Uncertainties and
risks remain, and are worth modeling
as sensitivities, but these are risks to
an asset’s valuation, not its technical
and commercial viability.
1
Source: Wood Mackenzie Exploration Service – October 2011 Company Performance: full cycle returns from
conventional exploration for the top 30 exploration companies
August, 2012 | 3
2
Conventional Asset Life Cycle
Exploration
Development
Production
Unconventional Asset Life Cycle
Concept
Pilot
Ramp - Up
Exploit
Figure 2 – Illustration of Acreage Quality Variability (Estimated Reserves
per Well) in the Barnett
Clay
Baylor
Jones
Taylor
Vio
la
Archer
Young
Throckmorton
Jack
Montague
Lim
es t
Grayson
on
Cooke
e
Mu
en Denton Collin
ste
rA
rch
Barnett Shale
Core
Wise
Tarrant
Shackelford Stephens
Abilene
Callahan
Palo Pinto
Dallas
Fort
Worth
Parker
Hood
Eastland
Johnson
nt
Haskell
Erath
Somervell
Runnels
Coleman
Bosque
Hill
Fort Worth
Basin
Texas
Comanche
Hamilton
Brown
Concho
Mills
Coryell
McCulloch
B ar
0
20
Source: Chesapeake November 2011 Investor Presentation, slide 15
4 | August, 2012
Appraisal
40
Menard
km
80
nett
S ha
Dallas
Ellis
l Fro
Operators have not traditionally
talked about making FID on a shale
asset; however, there is often a
Ramp-Up period, after the Pilot
stage in which financing is secured,
rig fleets and completion crews
are contracted, leases are drilled to
hold, midstream is built-out, etc.
The project then moves into the
Exploit phase, when development
drilling must continue to maintain
production (due to steep decline
Figure 1 – Asset Life Cycles
ctura
For unconventionals, Wood
Mackenzie defines Concept, Pilot,
Ramp-Up and Exploit life cycle stages.
During Concept, the operator tries to
identify prospective unconventional
resource targets, which do not
have any production history from
unconventionally drilled and
completed wells on which to base
a commercial evaluation. To fully
de-risk the concept, one must run
a Pilot drilling program to work out
the engineering and cost-benefit
tradeoffs that establish repeatable,
economically profitable results.
During these early two stages, it
is unclear whether a commercial
scale development program will be
viable. Thus, just as a conventional
field’s development cash flows are
risked, the same process should be
undertaken on the potential shale
development cash flows.
Stru
2) de-risking is a slower and a more
gradual process.
EUR (bcfe)
0.044 - 0.4
0.41 - 0.84
0.85 - 1.4
chita
1) the transition between stages for
unconventionals is far less discrete
than with conventional prospects,
and
The value and returns from
conventional and unconventional
assets share the same primary drivers:
price, production volumes, capital
costs, and fiscal terms, and they are
equally impactful across the life cycle.
The key driver of value that evolves
across the life cycle of a project/
prospect – ultimately the variable
with the largest impact on valuation
– is the sub-surface risk, or the
Commercial ‘Chance of Success’ (CoS),
quantified by combining technical
(Pg) and commercial (Pe) risks.
Q ua
The two biggest differences in
applying a similar life cycle approach
to unconventionals are:
Barnett Shale gas play (see Figure 2)
again illustrates play variability.
curves). During these later stages,
the ‘percent developable’ acreage
and well performance deviations
represent the major remaining subsurface risk that unconventionals
face that conventional fields do not.
Percent developable, along with well
spacing, is a direct determinant of the
number of well locations, and hence
remaining value of the undeveloped
portion of the asset. These later stage
risks can be quite substantial. For
example, a leading US operator of
shale plays has applied factors of 3075% developable to their established
positions.2 An analysis of the well
performance distribution within the
Bend Arch
Although it is an imperfect exercise,
mapping the conventional life cycle
and risk concepts to unconventionals
is key to successfully characterizing
unconventionals (see Figure 1).
1.5 - 1.9
Limestone
Waco
McLennan
Falls
2 - 2.6
2.7 - 3.3
3.4 - 4.4
4.5 - 6
6.1 - 8.2
le
San Saba
Kileen
Lampasas
Burnet
8.3 - 11
Source: Wood
Bell Mackenzie,ESRI Topography
Shale CoS < 1
In order to make appropriate
valuations and investment decisions,
one must understand the range of
CoS for unconventional opportunities.
The evidence is mounting that shales
are more risky and less homogenous
than originally perceived. Out of over
thirty shale gas plays in the US3, only
ten have emerged from pilots into
full development mode. While the
jury is out on several plays still being
tested, another ten have arguably
been proven non-commercial or face
numerous sub-surface and above
ground challenges. Stipulating that
there is a ‘failed play’ for every proven
shale suggests that the chance of
success for an entire play could be
around 50%.
Even when shale plays begin to
undergo serious Pilot efforts, they
do not emerge in their entirety as
a commercial play. The Niobrara is
a prime example of a play in which
heterogeneity has meant only a
subset of the pilots conducted in
the play are leading to commercial
development. The Pilot stage is also
one of delineation of core areas and
sweet spots, and even in largely
homogenous plays, the percentage
of acreage that is commercially
viable is far less than 100%. Examples
abound: success in the Eagle Ford is
concentrated along the narrow gasliquids transition window that runs
down the middle of the play. For the
Bakken, the top two out of seventeen
oil producing counties account for
more than half of the production in
North Dakota (though they host only
about a third of its producing wells).
Through a number of case studies
and M&A transaction analysis, Wood
Mackenzie has ‘back calculated’ a
range of implied CoS factors. At the
start of the Concept stage, CoS can
fall to around 10-20%, and at the
start of the Pilot anywhere from
20-50%. Although, as noted, there
is no exact point of transition from
Pilot to Ramp-Up – eventually the
acreage is proven, well performance
is established, and CoS approaches
100%. Relative to conventional
exploration, two key points stand out:
unconventionals are just as risky as
conventional exploration (commercial
success rates for conventional
exploration are generally 25-30%).
Secondly, CoS is de-risked far more
definitively and sooner in the life
cycle for conventional opportunities
than unconventionals. By the end of
the Exploration phase, a prospect’s
conventional CoS is near either 0% or
80-90% (except for marginal fields).
However, for unconventionals, CoS
will not have materially improved
between the Concept and Pilot
stages. In addition, CoS will improve
only gradually during the Pilot. The
implication is that a lot of the upfront
capital of a conventional prospect
is deployed during the less risky
Appraisal stage, while capital invested
during the Pilot is still very much at
risk, resulting in much higher ‘costs to
condemn.’
It is possible for operators to create
value at any stage in the life cycle. For
example, consolidating positions and
excelling at driving cost efficiencies
can create value during the later
stages in a play. However, the biggest
single opportunity for value creation
arises from derisking the acreage:
turning a land position originally
leased for less than US$500 per acre
into a proven property that can fetch
anywhere from US$5,000-US$25,000
per acre. The key value drivers evolve
over the life cycle of the project,
driven primarily by the chance of
success and the amount of capital put
at risk. For example, during the early
stages when risk is high and land
costs are low, maximizing the acreage
exposure provides significant value,
in the success case, as material upside
for a large number of well locations
and hence value creation.
However, during the later stages
when acreage access commands a
premium, percentage developable
and well spacing are the key drivers
of the number of well locations.
Nevertheless, adding acreage with
a high price tag fails to create value
– quality over quantity. Operators
that excel at ramping up quickly or
speeding up the learning curve can
use these capabilities to drive value
Table 1 – US Shale Gas Plays
3
Commercially Successful
Still Testing
Arguably Non-commercial
Still Conceptual
1
Barnett
Bossier
Conasauga
Pearsall
2
Eagle Ford
Utica
Floyd
Collingwood
3
Antrim
Monterey
Palo Duro
Cumnock
4
Huron
Niobrara (Powder River)
Chattanooga
Cow Branch
5
Haynesville
Niobrara (Piceance)
New Albany
Rhinestreet
6
Cana Woodford
Chattanooga
Barnett Woodford
Manning Canyon
7
Arkoma Woodford
Mancos
Baxter
8
Fayetteville
Cody
9
Marcellus
Gothic
10
Niobrara (DJ)
Pierre
Source: Wood Mackenzie Unconventional Gas Service – See Table 1
August, 2012 | 5
after a position is derisked, but these
effects are swamped by pilot stage
risks and uncertainties if they enter
a play early in its life cycle. At these
stages, the amount of money spent
on the pilot and the time it takes
to gather enough information to
commercially prove up the play are
much more important factors.
Recognizing the unconventional life
cycle stages and risk factors enable
more of a like-for-like comparison
between big exploration and shale
opportunities. Once one factors in full
cycle costs, CoS, and adjustments for
percentage of commercial acreage,
the IRR on a hypothetical Eagle
Ford project decreases from 27% to
15%, more on par with conventional
exploration (and that is for what is
arguably the most profitable shale
play today).
Portfolio Allocation Between
Big Exploration and Shale
Using the life cycle framework
enables one to acknowledge and
account for the fact that most
investment opportunity comparisons
are fundamentally not like-for-like.
The very real allocation decision
facing many large E&P companies
today is between their conventional
Figure 3 – Investment Profiles of Hypothetical Conventional and Unconventional Programs
10,000
400
8,000
320
6,000
240
4,000
160
2,000
80
0
0
-2,000
Production (mboepd)
US$ millions
Conventional Exploration Profile: DW GoM (Subsalt Miocene)
-4,000
-6,000
-8,000
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
Year
Licensing and E&A CAPEX
Development CAPEX
Net Operating CF
Cumulative CF (Disc. 10% to Year 1)
Production (mboepd)
400
8,000
320
6,000
240
4,000
160
2,000
80
0
0
-2,000
-4,000
-6,000
-8,000
0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Year
Land
Development CAPEX
Net Operating CF
Cumulative CF (Disc. 10% to Year 1)
Production (mboepd)
6 | August, 2012
Production (mboepd)
US$ millions
Proven Unconventional Profile: Shale (Eagle Ford)
10,000
exploration programs versus existing
shale asset developments. To consider
such a case, Wood Mackenzie
conducted a hypothetical exercise
for a company deciding between
allocating US$1 billion per year over
five years with the choice of either a
high-impact exploration program in
the Gulf of Mexico versus allocating
the funds to developing an existing,
proven Eagle Ford shale position.4
In this case, the two options offer very
different value propositions to the
company. The expected outcome (full
cycle, factoring in exploration risk)
for the GoM campaign should yield
twice the reserves as the Eagle Ford
program and three times the NPV.
However, because the discovered
fields will take time and capital
to develop, production comes on
significantly later (peak production at
year 11 versus 5), and the maximum
cumulative cash impairment will
exceed US$8 billion before beginning
to payback. At the end of the five
year period, the expected results
from the GoM exploration program
should provide the company a core
asset base worth US$17 billion from
‘company-making’ fields that will
provide US$3-4 billion in earnings
for decades.
The primary advantage of the Eagle
Ford development is nearer term
production and cash flows, which
also means that the maximum
cumulative cash impairment will be
around US$1-2 billion. Including the
cost of land results in a low 12% IRR
for the Eagle Ford project; yet, if a
company treats this cost as sunk, the
point-forward return will be greater
than 25% and appear more favorable
than the expected 16% return from
conventional exploration. Of course,
large oil companies typically allocate
their capital after considering a
range of financial and operational
metrics (not just IRR) to ensure that
the investment delivers a balance of
near-term, medium-term and longterm performance. IRR typically favors
short-term, incremental investments,
so it is also important to look at
metrics such as DPI (Discounted Profit
to Investment) which better reflect
the absolute scale of an investment
opportunity (in terms of a significant
longer term potential NPV, which may
take years to realize and have a lower
IRR). In this example, the Discounted
Profit to Investment (DPI5) ratio of
the deepwater GoM campaign is
dramatically higher than that of the
Eagle Ford (1.46 vs. 1.07).
In this example, the company has
drilled out all its Eagle Ford locations
after five years and cash flows will
begin dropping from US$1 billion to
US$500 million in just a few years.
In contrast, the GoM exploration
campaign is expected to deliver
a core set of assets that will be
developed and yield substantial
cash flow for the long run. The
longevity and size of this investment
opportunity combined with its higher
DPI multiple results in a substantially
higher NPV. The ultimate allocation
between the two will be driven
to some degree by whether the
corporate portfolio has the strength
to support a long-term conventional
program or has near-term shortfalls
and constraints that require the quick
production and self-funding of the
shale program.
Project Sensitivities
It is also critical to recognize how
the marginal nature of shale projects
will impact a portfolio’s exposure to
commodity and price risks. When
comparing later life cycle stage assets
(e.g. Development vs. Ramp-Up,
Production vs. Exploit), exploration
risk and CoS factors are no longer
relevant. At that point, one must
consider the usual key uncertainties:
volumes, price and cost. In this case,
the valuations of the unconventional
assets are far more sensitive, mostly
due to their significantly higher
breakevens. For example, a Bakken
project may have a breakeven in the
US$50 / bbl range, versus a large,
discovered Gulf of Mexico field with
a breakeven around US$15 / bbl. In
this instance, a 20% change in the
Figure 4 – Value Sensitivities of Hypothetical Conventional
and Unconventional Development Projects
Impact on Total After Tax NPV with a +/- 20% change in…
Price
Volumes
CAPEX
Conventional Downside
Conventional Upside
Unconventional Downside
Unconventional Upside
OPEX
-150% -125% -100% -75% -50% -25%
0%
25%
50%
75% 100% 125% 150%
4
For the purposes of comparison and analysis in this Perspective, both hypothetical programs have been idealized and normalized, and therefore do not capture many of
the complex dynamics observed in reality. For example, we have made simplifying assumptions that the unconventional project evenly drills its well locations over five years,
well performance is constant, and there are not any infrastructure delays or bottlenecks.
5
DPI = (Full Cycle Project NPV) / (Discounted CAPEX) + 1
August, 2012 | 7
volume of the GoM field may result
in a 30% change in NPV, but a 20%
change in well EUR in the Bakken will
swing the NPV plus or minus 125%
(see Figure 4). A change in price has
just a slightly greater impact. This
level of volatility in commodities is
commonplace and volumes are highly
uncertain, but while the conventional
field economics can suffer a setback,
the Bakken project is at risk of being
uneconomic. For many shale gas
producers, this phenomenon is all
too real. In this light, unconventionals
are riskier than conventional fields
especially during the development
phases.
The value of unconventional projects
is also far more sensitive to costs than
conventional projects. In the case of
OPEX, the impact on conventional
projects is insignificant, whereas OPEX
is still relevant for unconventionals.
This may represent an
underappreciated long-term risk for
unconventionals, as there is limited
experience with and information
on the long-term operating costs
and maintenance requirements for
the tens of thousands of shale wells
being drilled, particularly for those
producing liquids.
The investment profiles of
conventional and unconventional
assets can be highly complementary
and can work in tandem at a
corporate level, as depicted in
Figure 5. Early production from
unconventionals fills the void of
long conventional cycle times. This,
in turn, provides early positive cash
flows, helping to offset the otherwise
deep, standalone cash impairment
of a conventional opportunity
(provided that companies do not
reinvest free cash flow back into
the unconventional projects, as
has often been the case). Reserve
volumes ‘average out’, but because
the conventional assets will dominate
the portfolio on a value basis, the
overall portfolio rate of returns will
tend towards the conventional
exploration investment returns.
Conventional and unconventional
assets can also be complementary
within a portfolio because they offer
different risk profiles (types of risk
and timing), theoretically providing a
potential source of diversification for
the overall risk profile of the portfolio.
Given their typically much larger
acreage footprint, unconventional
assets can also provide a great deal
of resource upside potential with
future technology improvements.
The key is managing unconventional
assets within the portfolio with full
appreciation of their life cycle stage
and risk characteristics.
Conclusion
With the benefit of experience, we
now understand that unconventional
resource plays and shales in particular
are just as risky as conventional, highimpact exploration. Additionally, the
nature of their risk evolves in a less
definitive manner over their asset life
cycle, and the residual risks (percent
developable) and uncertainties
(marginal economics) are more severe
for unconventional assets even during
the development stage. However,
there is a role for unconventionals
in the corporate portfolio, so long
Figure 5 – Investment Profile of a Hypothetical Portfolio with Conventional and Unconventional Assets
400
8,000
320
6,000
240
4,000
160
2,000
80
US$ millions
10,000
0
0
-2,000
-4,000
-6,000
-8,000
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
Year
Licensing and E&A CAPEX
Development CAPEX
Net Development CF
Cumulative CF (Disc. 10% to Year 1)
Production (mboepd)
8 | August, 2012
Production (mboepd)
Expected Profile: Combined Portfolio
as companies employ frameworks
and approaches for evaluating
risk that enable them to compare
unconventional and conventional
opportunities on a near like-for-like
basis. With so many variables and
unknowns with unconventional asset
modeling, it is critical to identify
which ones deserve the most upfront
scrutiny. This is largely determined
by the asset’s current life cycle stage.
With unconventionals, there is a
temptation to focus on the more
well understood engineering and
operational assumptions; however, it
appears more and more that strong
technical and commercial evaluations
of risks and uncertainties are far
more important.
Wood Mackenzie’s consultants
provide strategic advice based on
real substance to clients in the global
energy, metals and mining industries.
We have been helping clients
understand the energy and natural
resource industries for four decades
with industry leading research and are
now leveraging that knowledge to offer
advisory services across the energy
value chain. With established presence
in the Americas, Europe, Asia/Pacific
and the Middle East, our consultants
offer a truly global view for questions
that must be considered in a global
context.
Authors
Neal Anderson
Head of Consulting
T +1 713 470 1624
E [email protected]
Preston Cody
Managing Consultant
T +1 713 470 1658
E [email protected]
www.woodmac.com/consulting
Perspective content subject to copyright, which can be found at: www.woodmac.com/disclaimer
August, 2012 | 9
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