Modeling Oil & Gas Fracking Business Performance and Sustainability
Using Continental Resources, Inc. as a Proxy (NYSE: CLR)
Introduction
Anyone who follows news and commentary on the oil and gas industry knows that there are two
opposing, equally vociferous camps with an opinion on the future viability of America’s “unconventional” oil
and gas industry. On the one hand supporters claim a U.S. energy renaissance is occurring that will propel the
country toward a long future of energy independence. This is due they say to the vast reservoirs of oil and gas
locked in extensive shale deposits that have been liberated by the modern application of horizontal drilling
and hydraulic fracturing or fracking. Phrases such as “awash in oil” and “natural gas glut” and “a hundred
years of affordable clean energy” and even “Saudi America” are routinely bandied about in the mainstream
press. And it’s true. U.S. production of oil and natural gas has veritably boomed since 2007 because of
horizontal drilling and fracking operations, a point continually being made in lobbying to the public by
industry-backed, often TV advertised website organizations such as energyfromshale.org,
energytomorrow.org, chooseenergy.org, and energyindepth.org.
On the other hand critics of the industry claim that it will be relatively short-lived, made possible only by
high energy prices and low interest rates as production costs rise due to having to drill ever more difficult
and lower quality locations. The phrases they apply are “Ponzi scheme” and “flash-in-the-pan” and “Red
Queen syndrome” referring to having to drill more and more wells just to keep production flat as earlier wells
quickly decline in output. Their voice obviously does not have the financial backing of the industry, but their
message gradually is finding its way into respected mainstream media. Consider the following headlines from
BusinessWeek, U.S. Shale-Oil Boom May Not Last as Fracking Wells Lack Staying Power, and from Bloomberg,
Wells That Fizzle Are a ‘Potential Show Stopper’ for the Shale Boom, and Shale Drillers Feast on Junk Debt to
Stay on Treadmill.
So the debate continues over the ultimate trajectory of the unconventional oil and gas industry with both
sides concentrating mostly on data related to the resources in the ground. Optimists point to past production
increases, additions to proved reserves, continuing technological innovations, and the existence of gigantic
fields that have yet to be extensively developed such as in the Anadarko and Permian basins. Pessimists point
to high production decline rates of both wells and fields, “hi-grading” practices (i.e., drilling the most
productive, highest return areas first), and increasing costs as drillers are forced to move into more difficult
resource locations. Others also point to future limitations ranging from the unavailability of water to local
legal/political backlash to inevitable environmental catastrophe. But what is also needed in this discussion is
a real-world look into the business enterprise nature of the industry and what trajectory it may be on. That is
the subject of this exercise.
Rather than attempt to construct an abstract model of production economics from industry statistics, a
more real-world approach was used by selecting and studying an actual company as a proxy, one that
arguably would be representative of large-scale fracking businesses generally. Continental Resources, Inc.
(NYSE: CLR) was selected for this purpose. The model is based on actual operating data from Continental
Resources as publicly reported in their SEC filed 10-K and 10-Q statements from 2007 to Q2 2014. The
company was chosen for its size, industry prominence, and technological advancement to represent large-
scale and leading-edge fracking operations. The company's data was analyzed to determine the underlying
trends and relationships between producing assets, oil & gas production, cash flows, long-term debt and
other factors. These data and relationships were then used to construct both a historical and future model for
projecting the economic performance of the fracking business under different assumptions.1
1 DISCLAIMER: Although the model is a statistical representation of aspects of the company’s performance over this period, the
reader should be careful to note that it is not intended to be used to forecast the future performance of Continental or any other
2
Continental Resources, Inc.
Started in 1967, Continental Resources is an independent crude oil and natural gas exploration and
production company with properties in the North, South and East regions of the United States. It focuses its
exploration activities in large new or developing crude oil (primarily) and also liquids-rich natural gas plays
that provide it the opportunity to acquire undeveloped acreage positions for future drilling operations. Their
claimed business strengths include a large acreage inventory, experience with horizontal drilling and
enhanced recovery methods, control over operations on a large majority of its assets and investments, an
experienced management team, and a strong financial position.
The company is at the forefront of advanced drilling and production technologies having drilled their
first horizontal well in 1992 and over 2,100 horizontal wells since that time. They are a leader in the
development of new drilling and completion technologies. For instance, their ECO-Pad drilling operation
allows for drilling multiple wells from a single pad, which is becoming a standard drilling approach in the
industry improving land use and increasing operating efficiencies. (Taken from their 2013 10-K.)
It is reported that Continental has significantly increased its leasehold in the deep Anadarko Basin
adding significant reserves with perhaps the same productivity expectations as it core holdings in the Bakken.
Recent drillings in the Springer Shale indicate that production economics may even exceed its existing
position in the similarly situated Woodford Shale. Therefore the company may continue to sustain a similar
production experience into the foreseeable future as it had in the past, which further makes it a good
candidate for modeling purposes, although other companies certainly may not be in the same situation (refer
again to the above disclaimer). Thus Continental is a fine representative of a large-scale, successful company
in this industry applying the latest in technological advancements with continuing future prospects.
A lot of discussion about energy companies’ financial potential in their own reports revolves around
their estimates of current proved developed and undeveloped reserves to be recovered in the future and their
“PV-10” calculations (the estimated net earnings to be generated from the production of proved reserves at a
10% discount rate). Ordinary stock investors meanwhile will look at traditional valuation measures such as
forward price-earnings ratios and profitability, which at the date of this writing (October 30, 2014) for
Continental was a respectable 14.94 and 15.27% respectively (Source: finance.yahoo.com). But simple metrics
like these belie the enormous complexity of energy companies like Continental that have many more moving
parts than even a sophisticated manufacturing company like General Motors. For instance, geologic
exploration and analysis, production rights acquisition, and commodity price management are required in
this industry in addition to developing production facilities, procuring services, and establishing distribution
capability.
Moreover, energy companies rely on continuing capital(ized) expenditures to maintain and grow
production, which makes those expenditures more of a variable expense than a fixed cost. As
Continental puts it, “Growth Through Drilling.” And therein lies one of the important keys to the
business performance and sustainability of oil and gas fracking, one that GAAP accounting for
earnings inadvertently helps to obscure.
The Model
Our model bypasses any earnings “distortions” created by property capitalizations, depletion
allowances, amortizations and impairments, etc. Instead it focuses on cash flows—for accumulated assets,
production activity and their financing. Note that with even a reported market cap of over $20 billion,
Continental pays no dividends, and cannot pay dividends without borrowing to do so. This may not be an
individual company, and it may under any given set of assumptions project results that may differ significantly from any particular
company's actual performance in the future. The model also is not intended to provide any investment guidance about any company
involved in the oil and gas fracking business.
3
issue for investors currently, but it does highlight the reality of a business model based on continually
growing capital expenditures, which may or may not be sustainable or have a favorable long-term outcome.
Consider for instance some of Continental’s data converted into indices in order to compare relative
rates of growth. These are: Long-Term Debt, Interest Expense, Total Investment in Property and Equipment
Assets, Barrels of Oil Equivalent in Thousands (MBoe) Produced, and Price-Adjusted Net Cash Flow.
This chart clearly shows a business growing via capital acquisition and financed out of both cash flow
and additional debt. It also is clear that the trend in the relationship between long-term debt and net cash
flow from operations is not sustainable on its current path, at least not indefinitely so. While this might look
expectedly alarming to industry critics, it cannot be inferred that Continental (or other fracking companies
growing in the same fashion) are on some kind of inevitable financial collision course.
To address this issue, our model quantifies the relationships between assets, production, cash flow and
debt, allowing a better evaluation of future trajectories, subject of course to the earlier disclaimer.
The primary relationships employed are as follows.
1)
Total Property and Equipment (TPE) drives Production.
2)
Production (MBoe, or Thousand Barrels of Oil Equivalent) drives Cash Flow.
3)
Increases in TPE Offset by Cash Flow drives Long-Term Debt.
4
Total Property and Equipment (TPE) and Production (MBoe)
Property and equipment is the “factory” of the oil and gas business. Except for advances in production
technology and drilling techniques, in order to grow production (or maintain it if well production rates are
falling) you need to grow your factory. But unlike a manufacturing facility where structure design and build-
out is under the control of the company, geology on the other hand for instance is not. Geology, drilling rights
availability, and perhaps infrastructure access as well dictate how fast and how much you need to “acquire”
(i.e., lease or purchase) new properties to achieve production goals.
While the direct relationship between current TPE and production is very strong, it may be argued that
it could introduce a bias since new additions are only fully developed over a subsequent period of years. For
Continental, newly booked proved undeveloped reserves (PUD) are expected to be developed within five
years. Therefore in this model, we reach back to accumulate prior plant and equipment additions as Total
Assets In Production (TAIP) as follows ; 100 percent of Year -4, 80 percent of Year -3, 60 percent of Year-2, 40
percent of Year-1, and 20 percent of the current year. End-of-year balance sheet amounts for assets (and later
for long-term debt) are averaged to reflect middle-of-the-year (“moy”) amounts.
The relationship between
MBoe by Estimated Assets in Production
70,000
MBoe and estimated TAIP is
y = 0.0067x + 4183.8
shown at the right. 2014 mid-year
R² = 0.9871
2014
results were annualized based on
60,000
daily production increases over
the same period in 2013. The
50,000
2013
linear trend is highly significant
and will be used in the model.
40,000
2012
However, the curve of the
30,000
data points (if 2014 is correct)
suggests a trend more like in the
2011
20,000
chart below, which could be the
2010
expected trajectory of a growing
2009
10,000
2008
business entering a maturity
2007
phase. Thus it could be the
0
consequence of the decline rate
0
1,000,000
2,000,000
3,000,000
4,000,000
5,000,000
6,000,000
7,000,000
8,000,000
9,000,000
10,000,000
Est. Assets In Production ($000) at MOY
discussed above, as unimproved
wells are accumulated or if new
MBoe by Estimated Assets (TPE) in Production
properties are becoming less
70,000
productive on a dollar-for-dollar
MBoe
basis.
2014
60,000
y = -0.0000000x3 + 0.0000000x2 + 0.0003912x + 9,095.6069856
A leveling off of production
R² = 0.9981790
vis-à-vis TPE may or may not be
50,000
2013
the case; it could just be
coincidental variations in the
40,000
annual data. But even if
2012
productivity leveling is true for
30,000
core properties in the Bakken, the
2011
anticipated productivity of the
20,000
new fields to be developed in the
2010
2009
Anadarko SCOOP (South Central
2008
10,000
2007
Oklahoma Oil Province) could set
0
0
1,000,000
2,000,000
3,000,000
4,000,000
5,000,000
6,000,000
7,000,000
8,000,000
9,000,000
10,000,000
Est. Assets In Production ($000) at MOY
that trajectory back on a more liner path for some time. It’s also best to remember that at some point,
attempting to build more complexities into a model can become just an exercise that only introduces greater
“assumption risk.”2
Cash Flow
“Earnings may make for a more consistent financial statement presentation, but in the end only
cash pays the bills.”
Some in the industry have referred to it as following a “manufacturing model.” That is, “to produce more
oil, we simply drill more wells” (growing the factory). But drilling more wells overall means incurring more
capital expenditures for exploration, acquisition, and development (EAD), which must be financed to the
extent that available operating cash flow is insufficient. Like many oil and gas frackers, Continental’s cash
flow after EAD is negative.3 This indicates the extent to which Continental has pursued growth, increasing
moy TPE at a compound annual growth rate of 42 percent from 2007 to 2014.
Continental Resources
Summary of TPE and Cash Flow
$thousands
2007
2008
2009
2010
2011
2012
2013
2014e
Total Property and Equipment (TPE)
1,364,448
2,077,989
2,728,641
3,487,079
5,111,501
8,194,586
12,033,296
15,885,945
Pct. Change
52.3%
31.3%
27.8%
46.6%
60.3%
46.8%
32.0%
Net Cash Flow From Operations
390,648
719,915
372,986
653,167
1,067,915
1,632,065
2,563,295
3,051,758
Exploration, Acquisition & Development
(483,498)
(927,617)
(499,822)
(1,039,416)
(2,004,714)
(3,903,370)
(3,711,011)
(4,172,952)
Net Cash Flow After EAD
(92,850)
(207,702)
(126,836)
(386,249)
(936,799)
(2,271,305)
(1,147,716)
(1,121,194)
A financial aim of business of course is to generate the cash flow necessary to both service its debt and
provide an acceptable yield for shareholders commensurate with their risk. Having estimated MBoe based on
total property and equipment in production, the second step in the model therefore is to convert that
production into cash flow. However, to avoid any distortions introduced by changing prices over time, we
first have to price-adjust the actual cash flows to reflect constant pricing. The constant pricing is based on the
latest prices the company received for oil and natural gas in Q2 ’14 weighted by production for each year.
Those prices were $92.31 per barrel of oil and $5.43 per thousand cubic feet (Mcf) of natural gas. The price
adjustments are shown below.
Continental Resources
Price Adjustment Calculation
$thousands
2007
2008
2009
2010
2011
2012
2013
2014e
Oil and Natural Gas Revenues (rev)
606,514
939,906
610,698
948,524
1,647,419
2,379,433
3,606,774
4,560,037
Total Revenue Adjustment Factor (f)
1.395
1.007
1.695
1.295
1.042
1.114
1.027
0.993
Net Cash Flow From Operations
390,648
719,915
372,986
653,167
1,067,915
1,632,065
2,563,295
3,051,758
Revenue Adjustment (f-1)*rev
239,574
6,312
424,177
279,666
69,448
271,023
99,055
(33,368)
Price-Adjusted Net Cash Flow
630,222
726,227
797,163
932,833
1,137,363
1,903,088
2,662,350
3,018,390
2 It may be asked why total assets are used as a driver rather than net assets after depletion write-downs, amortizations,
depreciation, etc. Property sales, although not too significant, are accounted for, but the model uses a total sunk investment cost
approach, and the ongoing and accumulating carrying cost is the ultimate target of the model. For example, a factory that rolls over its
financing liability but is half depreciated away on a net basis would look twice as productive today as when it went into service. Besides,
using that approach would only change the relationship inputs to the model, not the results.)
3 As of 2013, 7 of 9 of the top natural gas producers operating primarily in the highly productive Marcellus Basin for example also
reported negative cash flow after EAD.
6
The chart below shows the relationship between production and price-adjusted cash flow (including
interest expense).
$000
Price-Adjusted Cash Flow* to MBoe Produced
3,500,000
y = 48.2520x + 138,387.4465
R² = 0.9937
3,000,000
2,500,000
2,000,000
1,500,000
1,000,000
500,000
*Net Cash Flow from
Operations adjusted for
constant Q2'14 prices.
0
0
10,000
20,000
30,000
40,000
50,000
60,000
70,000
MBoe Produced
Similar to the production charts, a critic might surmise that the data points are really indicating a growth
followed by a flattening trend after 2013 suggesting perhaps that production costs per Boe are increasing as
the company’s drilling territory
expands. But there are other
$000
Production Expenses by MBoe
expenses involved in operations
400,000
y = 5.1903x + 23033
under discretion of management,
R² = 0.9927
350,000
and one-time extraordinary items,
that could signal a false trend. As
300,000
the chart on the right shows,
production expenses alone indeed
250,000
are tightly correlated, over 99
percent, with production.
200,000
Therefore in the model, the linear
150,000
relationship indicated above will
be used.
100,000
The other key cash flow
consideration is the relationship of
50,000
exploration, acquisition and
0
development expenses (EAD) to
0
10,000
20,000
30,000
40,000
50,000
60,000
70,000
MBoe
annual TPE additions. This should
be an obvious correlation, so we
can use this relationship to drive the model’s EAD projection based on TPE growth, separately from operating
7
cash flow, and hence to determine the net effect on the company’s long-term debt position. (In the model,
EAD in excess of net cash flow requires an increase in debt while cash flow in excess of EAD is used to retire
debt.) This relationship is shown in the chart below.
EAD Expense by Incremental Property and Equipment
4,500,000
y = 0.9948x + 1819.9
R² = 0.9957
4,000,000
3,500,000
3,000,000
2,500,000
2,000,000
1,500,000
1,000,000
500,000
0
0
500,000
1,000,000
1,500,000
2,000,000
2,500,000
3,000,000
3,500,000
4,000,000
4,500,000
Incremental P&E End-of-Year (EOY)
Long-Term Debt
The last element of this
exercise is the estimation of long-
$000
Long-Term Debt to Total Property and Equipment
7,000,000
term debt, which determines the
y = 0.3965x - 641,605.0268
ongoing financial viability of the
R² = 0.9923
6,000,000
company (under different
projection assumptions) and the
5,000,000
company’s ability to reduce debt
to an acceptable level while
4,000,000
providing an appropriate return
for shareholders. Historically
3,000,000
Continental’s long-term debt is
strongly correlated with TPE
2,000,000
assets since net cash flow has not
covered EAD expenses at
1,000,000
Continental’s rate of growth. That
relationship is shown at the right.
0
0
2,000,000
4,000,000
6,000,000
8,000,000
10,000,000
12,000,000
14,000,000
16,000,000
18,000,000
(1,000,000)
Total Property and Equipment (moy)
8
All the above primary relationships for Continental Resources: assets-to-production-to-cash flow-to-debt
and their statistical results are used in the model to recast 2007-2014 without any year-to-year anomalies.
Projections after 2014 are based on assumptions about the future growth curve in TPE and changes in future
production efficiencies, prices, and debt retirement. Production is projected by extending the model’s
historical trend in Boe-per-$1,000-of-TAIP. Production also is split into estimated new versus existing well
production, based partly on assumed new well and field decline rates (60 percent for Year 1 and 20 percent
yearly thereafter, which reconciles well with the TAIP-to-MBoe trend).
Finally two adjustments are made to project price-adjusted cash flow (PACF) as asset acquisition,
production, and debt retirement deviate from the historical trends that drive the model. The first adjustment
is made to assume that if production growth slows, or goes into decline, the production expense portion of
cash flow will remain “sticky” and stay at elevated levels since they are more related to operating the existing
base of wells than they are to the actual production from those wells.4 The second adjustment is made to
recognize that the interest expense component of cash flow will decline as LTD declines, which is
independent of the relationship of cash flow to production.
The Results
Several scenarios are presented here so the reader can better judge for him or herself how viable the
future is for a large-scale fracking business and whether or not the description of “energy renaissance” or
“Ponzi scheme” fits. Again, these are not meant to be forecasts of Continental or any other particular business
since there are too many other factors that come into play that are unique to each company such as their
negotiating position in drilling deals, financing attractiveness, price hedging practices, merger and acquisition
potential, ability to employ technological advances, bargaining power in securing water, sand and other
resources, etc. Yet a model like this, even at its basic level of complexity, should provide an additional and
needed dimension to the fracking sustainability debate.
Also keep in mind that the model only projects out to 2020, so what is shown as the trend at that time is
not guaranteed to continue further into the future. Even at low rates of growth, there may come a time when
profitable drilling locations simply run out, financing dries up, resources become unavailable, public
sentiment turns negative and anti-fracking laws are passed, or some other show-stopper occurs. With all the
geophysical, economic, and political uncertainties in play, projecting almost anything beyond a few years is an
exercise in fantasy. These are the scenarios considered here:
Business as Usual (BAU). The company continues its current TPE growth at a 42 percent CAGR.
Declining Growth A. Annual TPE growth declines continually to 5 percent by 2012.
Declining Growth B. Annual TPE growth declines but with better drilling efficiency and lower prices.
Declining Growth C. Annual TPE growth declines with no efficiency gains but higher prices.
Fixed Growth. Annual TPE growth after 2014 is fixed, with the same efficiency and higher prices.
Black Swan Event. Something happens that halts all company drilling (i.e., zero growth) by 2017.
4 While it is true that marginal wells could be (and are) taken out of production, it is equally true that the company could use
enhanced recovery techniques to keep existing well production as profitable as possible. This assumption also can be turned off in the
model.
9
Business as Usual (BAU). The company continues its current TPE growth at a 42 percent CAGR.
This scenario is a good lesson in exponential math. It literally takes the company “off the charts.”
Production would have to be raised to nearly 500 million Boe annually, or 7.7 times 2014 production. Net free
cash flow continues to go south while long-term debt skyrockets. It’s safe to say that this result is beyond
even the imagination of the industry’s most ardent optimist. Needless to say, market shareholders would get
no return on their investment.
Declining Growth A. Annual TPE growth declines continually to 5 percent by 2012.
10
In this more realistic scenario, TPE additions decline continually from their current growth (42 percent
CAGR) to 5 percent by 2020 assuming current production efficiency and Q2’14 price level. This still would
demand an almost 3x increase in production that would level out by 2020 and drop thereafter. However, free
cash flow, after reducing debt to 30 percent of its peak, would be sufficient to reward market shareholders
with a 2015-20 annual yield of 16.9 percent. But depending on how the debt is paid down, those shareholders
might have to wait as long as 2019 to see any of that return.
Declining Growth B. Annual TPE growth declines but with better drilling efficiency and lower prices.
This case assumes that the company can increase new and second-year well production by 15 percent.
However, offsetting this is a 10 percent decrease in oil and gas prices. Note that production is up from the
previous case due to enhanced efficiencies, and production still appears to be on an upward trend by 2020,
but the yield for shareholders remains about the same.
The industry believes that more gains in production efficiency (or productivity), through more improved
technology and drilling practices will yet be realized. Certainly in this example of just a 15 percent gain in
new well productivity5, a significant impact on output is realized enough to offset an overall price decline of
10 percent. Whether actual production gains will be more or less than this, should the industry continue on
this production trend, it could indeed put this kind of pressure on prices depending on U.S. and world
demand and marginal oil and gas project costs at the time.6
5 The model and this paper refer to new versus existing wells as a convention for simplicity. One should not think that a “new” well
is necessarily drilled for the first time and then becomes an addition to the stock of “existing” wells the next year. In fact the industry may
employ new technology not just on newly drilled wells, but on previously drilled wells that indicate the potential for additional enhanced
recovery.
6 As of the writing of this paper, WTI spot prices fell from $107 at mid-June to $81 by the end of October, a 24 percent drop in just
4½ months. Brent fell by 25 percent as well over this period.
11
Declining Growth C. Annual TPE growth declines with no efficiency gains but higher prices.
If efficiency improvements do not materialize but energy market prices increase by 15 percent, free cash
flow rises to where market shareholder annual returns top 30 percent. With the same percentage of efficiency
improvement, returns could reach over 45 percent. Of course like the previous cases, the company would still
have to see a nearly 3x increase in production by 2020.
Fixed Growth. Annual TPE growth after 2014 is fixed, with the same efficiency but higher prices.
12
This case assumes that TPE growth quickly levels out at a 10 percent annual rate through 2020.
Production levels out and enters a slight decline by 2020 at less than 2x current production. Free cash flow
starts to decline at a faster rate, but provides market shareholders with nearly a 30 percent annual yield over
that period.
Black Swan Event. Something happens that halts all company drilling (i.e., zero growth) by 2017.
In this situation some event results in a complete halt to the expansion of the fracking business in 2017.
Debt must be fully paid back, but market prices shoot higher. Both factors contribute to quickly increasing
cash flow available for shareholders who may yet reap a 35 percent yield, although the value of the stock
itself is in substantial doubt. With both production and cash flows decreasing, shareholders might be repaid
their capital investment with a return, in time, provided production is not stopped altogether.
Conclusions
Although more extreme assumptions were not used in these scenarios, some consistent observations
still can be made about the fracking business model in general.
1.
Current rates of (TPE) growth will not be sustainable for any long-extended period of time.
2.
Increasing high-yield debt leverage to fund net EAD costs is a consequence of companies’ current
ability to expand operations to build future cash flow, but not necessarily a need to prevent any
imminent decline.
3.
Any reduction in the growth of TPE reduces EAD costs and consequently frees up operating cash
flow sufficient to both retire debt and still potentially provide a significant shareholder return, at
least through 2020.
4.
The more realistic scenarios above project about a 2-3 times increase in production (over 2014) by
2020. This would equate to four more years, until 2018, at current annual increases of about 25
percent. While this seems achievable based on the last seven years’ trend (a point hotly contested
13
between industry proponents and critics7), proved reserves estimates and future production
should be monitored closely to determine if a significant deviation from the model is occurring and
what the reasons are.
At the end of 2013, Continental reported total reserves of just over 1 million MBoe with a current
estimated production for 2014 at 61,800. This would easily accommodate our model’s production curve if
TPE growth were to stop by 2015 and no additional reserves were to be found on the company’s current
properties.
As to the fracking debate, the model indicates that large-scale unconventional oil and gas businesses
may be quite viable under a wide range of conditions, enough so to retire their debt if need be and still
provide a significant return to its owners. Certainly there are conditions, as seen above, that could put a
company on an eventual production decline and reduce it to being a cash cow for as long as the oil and gas
continue to flow. But it appears that any such transition could be managed in orderly fashion. However, what
a general production decline across the entire industry would mean for the economy could be a completely
different story.
Any questions about or requests for the model itself may be directed to the email address below.
Patin Associates Inc.
mp@patin.us.com
© Copyright 2014 by Patin Associates Inc. - All Rights Reserved
7 According to our reading, the average consensus of peak oil researchers has unconventional oil production in the U.S. (and maybe
natural gas as well) peaking at 2017 give or take a year while the U.S. Energy Information Administration (EIA) projects that “domestic
crude oil production is expected to level off and then slowly decline after 2020” with natural gas production continuing to increase at
least to 2040.
14